280Q47029030San Diego Gas & Electric Company008Q43102022-04-15100010San Diego Gas & Electric Company000Q402022-04-151200San Diego Gas & Electric Company001300Q42022-04-15000140San Diego Gas & Electric Company0Q42022-04-1500San Diego Gas & Electric Company00120Q42022-04-15000San Diego Gas & Electric Company000Q402022-04-1500002022-04-1517San Diego Gas & Electric Company35.043Q42022-04-1519San Diego Gas & Electric Company22Q42022-04-15San Diego Gas & Electric Company25Q42022-04-1528San Diego Gas & Electric Company35.054Q4292022-04-15San Diego Gas & Electric Company21.00135.0573421.002Q42022-04-1521.00335.059San Diego Gas & Electric Company21.004Q42022-04-1535.06121.005San Diego Gas & Electric Company35.063Q42022-04-1535.1223935.12345.02438035.1244045.0250390045.026035.12740035.12845.027041045.0284245.02935.13543014.06745.03004400035.13945.031045045.03209883625045.033145953651345.0340545.03507042.03314.00249.02640.00935.09642.03414.00349.02840.010167024695642.03514.00449.02935.098111015823042.03614.00549.03040.01135.14142.03714.00649.03135.10042.03814.00749.03240.01235.14242.03914.00849.03340.01342.04014.00949.03435.1432676345359042.04114.01049.03540.01435.0768253275451
Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking
Accumulated Provision for Depreciation & Amortization Classified
under FERC Seven Factor Test
In Accordance with Guidelines in FERC Order 888

Accumulated Provision
Electric
Intangible Plant 173,963,956 
Steam Production Plant 305,885,272 
Other Production Plant 272,588,028 
Transmission Plant 1,635,135,373 
Distribution Plant 3,606,168,212 
General Plant 219,537,534 
Ratemaking Electric 6,213,278,375 
Nuclear Decommissioning 1,011,036,365 
ASC 410 (FAS 143 and FIN 47) - Electric (1,018,731,937)
Capital Leases A/D 90,279,107 
Leased to Others- Citizens A/D (Sunrise) 29,238,086 
Leased to Others- Citizens A/D (SX-PQ) 2,234,053 
Cuyamaca Permanent Adjustment 17,855,747 
Total Electric 6,345,189,796 
Ratemaking Gas 1,161,217,848 
FIN 47 - Gas (215,090,648)
Total Gas 946,127,200 
Ratemaking Common 857,931,943 
FIN 47 - Common 2,922,489 
Capital Lease A/D 101,104,023 
Total Common 961,958,455 
Total Accumulated Provision EOQ 12/2021 8,253,275,451 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production 293,178,925 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production 284,106,681 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant 1,544,320,791 
35.14642.04249.03649.03740.0151851017813935.14849.03840.01635.1505.0015.00240.01735.1525.0035.00435.09340.01835.1555.00535.09535.1941140.08140.0711235.1951340.08240.0721435.19640.08340.07335.19740.08440.07435.19840.08540.07535.19940.08640.07635.20040.08740.07735.20140.08840.07835.20240.08940.07935.20340.09040.080San Diego Gas & Electric Company0114.0552Q42022-04-154414.0563San Diego Gas & Electric Company4Q42022-04-1550San Diego Gas & Electric Company600Q472022-04-15080San Diego Gas & Electric Company139795226666595609253Q402022-04-15100San Diego Gas & Electric Company4.00121.0001121.0014.00246Q42022-04-151221.0024.003San Diego Gas & Electric Company134.004Q41402022-04-154.005015San Diego Gas & Electric Company4.006011620Q44.0072022-04-1501734.0080San Diego Gas & Electric Company49.05049.05149.052035.01149.05301049.054135.016049.05521349.056035.020349.057819252902153049.05835.023449.06035.0251849.06150049.06235.0290212649.06330049.06435.0314247049.06535.1075035.034049.0666079146682276849.06735.1097321.000San Diego Gas & Electric Company56.002Q46.0032022-04-156.004San Diego Gas & Electric Company2.00013.0006.0052Q42022-04-154.0006.006676315223San Diego Gas & Electric Company4.0016.007251985004Q44.0022022-04-156.0084.003San Diego Gas & Electric Company6.00954.004Q46.0107.0012022-04-15614.0057.0026.011San Diego Gas & Electric Company5624.00677.0036.012Q42022-04-154.0077.00483San Diego Gas & Electric Company4.0087.00594.009Q4107.0062022-04-151144.010107.007San Diego Gas & Electric Company1254.0117.008Q413112022-04-154.0127.009San Diego Gas & Electric Company12035.159San Diego Gas & Electric CompanyElectric and Natural Gas Service - California0Q40false2022-04-1535.1604035.069San Diego Gas & Electric CompanySan Diego Gas & Electric Company0Q42022-04-1535.162Q42022-04-1514San Diego Gas & Electric Company35.164San Diego Gas & Electric CompanyQ4Q42022-04-152022-04-15035.166San Diego Gas & Electric CompanySan Diego Gas & Electric Company00Q4Q435.1672022-04-155.12022-04-1500San Diego Gas & Electric Company5.2035.16835.051Q405.32022-04-15035.169San Diego Gas & Electric CompanySan Diego Gas & Electric CompanyQ42022-04-151635.056Q42022-04-1535.171San Diego Gas & Electric Company35.173San Diego Gas & Electric CompanyQ40Q42022-04-152022-04-15040.01934040.0203536040.02137003840.022039040.02340041040.02404243040.025044040.0264504640.0274704840.0280490045.0361040.0911145.037646540.09245.03813288156940.09345.03911064702945.04040.0948344912345.04140.09545.0427640.0967745.04349.00140.09745.04449.00245.04549.00340.09849.00440.09949.005649.006740.1005285576949.008261589840835.204Q435.1102022-04-1535.206San Diego Gas & Electric Company35.112Q42022-04-1535.20735.114San Diego Gas & Electric Company8935.208Q42022-04-151035.117San Diego Gas & Electric Company35.2091135.121Q4122022-04-1535.210San Diego Gas & Electric Company35.126Q435.1762022-04-1535.130San Diego Gas & Electric CompanyQ435.17935.1322022-04-15San Diego Gas & Electric Company35.134Q42022-04-1535.136San Diego Gas & Electric Company35.185802400042.0750025042.076026048042.07727000280029030003100032000033000034035.071050350003635.072037035.0733801039035.0742400333535.14535.01335.01435.147944459405235.14935.018431442573216977298335.019235773227435.151194413363735.02235.15418349663272035.15835.027232635.16335.0333035.1654San Diego Gas & Electric Company042.0010Q42022-04-150042.0020San Diego Gas & Electric Company042.0030Q42022-04-1542.00400San Diego Gas & Electric Company8253275451
Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking
Accumulated Provision for Depreciation & Amortization Classified
under FERC Seven Factor Test
In Accordance with Guidelines in FERC Order 888

Accumulated Provision
Electric
Intangible Plant 173,963,956 
Steam Production Plant 305,885,272 
Other Production Plant 272,588,028 
Transmission Plant 1,635,135,373 
Distribution Plant 3,606,168,212 
General Plant 219,537,534 
Ratemaking Electric 6,213,278,375 
Nuclear Decommissioning 1,011,036,365 
ASC 410 (FAS 143 and FIN 47) - Electric (1,018,731,937)
Capital Leases A/D 90,279,107 
Leased to Others- Citizens A/D (Sunrise) 29,238,086 
Leased to Others- Citizens A/D (SX-PQ) 2,234,053 
Cuyamaca Permanent Adjustment 17,855,747 
Total Electric 6,345,189,796 
Ratemaking Gas 1,161,217,848 
FIN 47 - Gas (215,090,648)
Total Gas 946,127,200 
Ratemaking Common 857,931,943 
FIN 47 - Common 2,922,489 
Capital Lease A/D 101,104,023 
Total Common 961,958,455 
Total Accumulated Provision EOQ 12/2021 8,253,275,451 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production 293,178,925 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production 284,106,681 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant 1,544,320,791 
042.00516345189796009461272000Q4961958455042.006042022-04-153.001042.0073.002San Diego Gas & Electric Company642.008343.003Q42022-04-1542.0093.004119San Diego Gas & Electric Company12042.0103.005Q4002022-04-1542.011123.006000San Diego Gas & Electric Company42.01203.007014Q442.0133.0082022-04-15042.01403.009San Diego Gas & Electric Company00042.0153.010Q40022022-04-15042.0163.0118758536940.029802203151Q435.0752022-04-15091040.0300San Diego Gas & Electric Company35.078100Q401135.10440.0312022-04-1511035.079San Diego Gas & Electric Company121240.03218Q4132022-04-1535.08014San Diego Gas & Electric Company1340.03335.08215Q42022-04-15161440.034035.037San Diego Gas & Electric Company35.084017040.03515Q42022-04-1518035.08535.0380San Diego Gas & Electric Company1977781640.0360Q435.08607935.0392022-04-1501740.0378035.08735.0412081San Diego Gas & Electric Company40.038Q4182022-04-1535.08835.042San Diego Gas & Electric Company180660741.0018192529021.0021582449286235.187161.00311923121192312171.00435.1891845.0011.00545.0021.00614.001561.00745.003202114.0021.00845.0042214.0032314.00445.0052414.00545.0062514.00645.0072614.00714.00845.00814.00945.00914.01045.010614.00114.0111818440.04140.10119520640.10240.04221740.10322840.04323940.10440.0442410251140.10540.045261240.106271340.046281440.10740.047293040.10840.0483140.1093240.0493340.11040.0503494.0135.00649.06812114.014135.00749.069310538715134.0155.00849.070144San Diego Gas & Electric Company155.00949.071Q42022-04-15152.001175.01049.0722.002San Diego Gas & Electric Company19165.011502.003Q42022-04-15205.012172.004San Diego Gas & Electric Company215.0132.00518Q4235.0142022-04-152.00625195.015San Diego Gas & Electric Company2.007275.016Q4202.0082022-04-15295.0172.009San Diego Gas & Electric Company215.0182.010Q414.0152022-04-15222.01112San Diego Gas & Electric Company14.01613232.012Q414.017142022-04-152.0132414.0181500035.137040.12100035.13840.122000035.10640.123000035.10840.124000040.125035.11100040.1260035.1130040.1270035.118040.128013035.120040535.12507096188239Q42022-04-1535.06735.068San Diego Gas & Electric CompanyQ42022-04-152592280895San Diego Gas & Electric Company12398495226Q442022-04-15San Diego Gas & Electric Company6Q42022-04-159San Diego Gas & Electric Company12Q42022-04-1537128506514San Diego Gas & Electric Company426356105Q42022-04-15San Diego Gas & Electric Company121184972Q41084264842022-04-15San Diego Gas & Electric Company40.03900040.04015123935.170211386964165152435.17256835.14410112214316435.15317519635.1564177710105176062335.157210871521714.02939195146238414.03011.00011.00125935.161514.03111.0022710614.032197.010040.11135.04407.0114235.2052007.01240.112035.04542.04407.01321042.04540.1137.01435.046042.0462207.0153.140.11442.04735.0477.01635.183222342.0483.235.1847.01740.11535.04842.0493.37.0182442.0503.440.116035.049042.05125040.11742.05235.050026042.05340.118035.05242.054027042.05540.11935.05342.056282440.12042.05735.055San Diego Gas & Electric Company36414.009Q449.00935.0902022-04-1540.051Q4424.0102022-04-1549.010San Diego Gas & Electric Company35.0924.011San Diego Gas & Electric Company49.01140.052Q402022-04-1524.012Q40349.0122022-04-1535.094824492862San Diego Gas & Electric Company040.0534.01349.013San Diego Gas & Electric Company0Q44.0142022-04-15049.01435.097Q440.0542022-04-150100341024.015San Diego Gas & Electric Company49.015100341020San Diego Gas & Electric Company35.0994.016Q4049.01740.0552022-04-15Q48192529024.0172022-04-1549.018San Diego Gas & Electric Company3835.1011040.0564.018San Diego Gas & Electric Company1149.019Q42022-04-15Q449.02035.1022022-04-1540.057San Diego Gas & Electric Company049.021Q4035.1032022-04-1549.02240.058San Diego Gas & Electric Company0Q402022-04-15San Diego Gas & Electric Company049.023035.105040.059San Diego Gas & Electric CompanyQ449.02402022-04-150Q4049.02502022-04-15C00068540.0600Q435.1292022-04-1542.017San Diego Gas & Electric Company42.01835.131Q442.0192022-04-1542.02045.04635.133San Diego Gas & Electric Company42.02145.048Q402022-04-157.142.02245.049San Diego Gas & Electric Company042.02335.140Q4045.0512022-04-1542.0240San Diego Gas & Electric Company042.02545.0520Q442.0262022-04-15045.054042.027San Diego Gas & Electric Company45.05542.028Q482022-04-1535.11542.02945.05735.116San Diego Gas & Electric Company42.030Q42022-04-15042.03135.1190San Diego Gas & Electric Company42.0320Q4035.21225935.001112614.05735.2131335.0032714.0581535.21414.0592835.0051714.060202949.03935.00714.0612249.0403014.0622449.04135.00814.063312649.04214.06435.009283249.043114.0652949.04433335.01014.066311129850049.0453433449.04635.012353549.047559623423535.0153749.04891951463649.049635.0173714.0123114.0193.012314.0133214.0203.01314.01414.02143.01414.0223.015514.0233.01614.0243.017614.0253.01814.026714.027814.02811San Diego Gas & Electric CompanyQ4122022-04-151435.177falseValerie Bille1645.01114.03329145839545.01214.03445.01314.03514.03645.01414.03714.04380216536845.01514.03814.04445.01614.0392460564014.04514.04045.01714.04614.041659839958414.04745.01814.042607914668214.04845.01914.04945.02014.05056715991646785175127715414.05145.021641785900014.05245.02214.0536.0006.00145.02314.05429San Diego Gas & Electric CompanySan Diego Gas & Electric Company40Q42022-04-15301San Diego Gas & Electric Company48330 Century Park Court, San Diego, CA 92123Q453102022-04-15true0true0320San Diego Gas & Electric CompanyQ4O02022-04-1523302022-04-15San Diego Gas & Electric Company00Q4342022-04-1542San Diego Gas & Electric Company35Q42022-04-15361San Diego Gas & Electric Company020Q42022-04-1537030San Diego Gas & Electric Company21226.0010384Q46.00202022-04-15230292.0141035.17835302.01540.06135.0583635.07735.180312.0163740.06235.0602.0173235.181381040.0012.018640.063735.0623933035.18240.00235.08140140.06435.06424135.18640.003435.0834240.06535.065635.18840.004840.06635.06635.19040.005599748824410596601610540.06735.07012314721391.135.19140.0061.21435.08940.06835.0361.31635.19240.0071418973251.4132881569
Reclassification of FERC Form 1 2021 Materials & Supplies, Page 227, for Ratemaking
Materials and Supplies Classified
In accordance with Guidelines in FERC Order 888

EOY 2021
Total Materials and Supplies (FERC 154) 132,881,569  1
As Assigned to Department for Ratemaking
Electric Department 117,275,564 
Gas Department 15,606,005 
Total Allowable Materials and Supplies per FERC Formula 117,275,564 
Total 13-Month Average Electric M&S for 2021 121,247,303  2

1 Ties to Line 12 of FERC Form 1, pages 227

2 Ties to Line 1 of Cost Statement AL supporting workpaper, in TO5 Cycle 5 FERC Filing.
40.06935.0911.535.19340.00835.04040.070319162017211819202122232526274353285429553031323342.058035.02142.059042.060035.024042.06135.174029013160435.17542.062035.026042.063035.02842.0644418109892642.06535.03042.06642.06735.032042.0680035.03542.069042.0700235.0020542.0710842.0727035.00481142.0739281435.00642.074
C000685 MISSION_3, San Diego, Transmission, Unattended 2021-01-012021-12-31 C000685 TRANSMISSION FIBER OPTIC NETWORKferc:ElectricUtilityMember 2021-12-31 C000685 SUBSTATION SECURITY PROJECTSferc:ElectricUtilityMember 2021-12-31 C000685 HELICOPTER INFRARED CAMERAferc:ElectricUtilityMember 2021-12-31 C000685 ORANGE COUNTY LONG RANGE PLAN 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 D. 21-08-031 DE-ENERGIZATION POWER LINES 2021-01-012021-12-31 C000685 DISTRIBUTION, 370.11 2021-01-012021-12-31 C000685 (2) Research Support to Edison Electric Inst., NONE 2021-01-012021-12-31 C000685 GRANITE, El Cajon, Distribution, Unattended 2021-01-012021-12-31 C000685 LAS PULGAS_2, JAPANESE MESA, OH, 2021-01-012021-12-31 C000685 Miguel 60 Tap, Miguel, 1S, 2-900 ACSS/AW 2021-01-012021-12-31 C000685 PENDLETON, Oceanside, Distribution, Unattended 2021-01-012021-12-31 C000685 Sunrise Fire Mitigation Liability 2020-12-31 C000685 San Onofre_1,  , 1S,3, 1-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 5.350% Series BBB due 2035 2021-12-31 C000685 Manzana Wind LLC, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 LS1 2021-01-012021-12-31 C000685 CREELMAN, Ramona, Distribution, Unattended 2021-12-31 C000685 MESA RIM, San Diego, Distribution, Unattended 2021-12-31 C000685 TL628 CABLE REPLACEMENTferc:ElectricUtilityMember 2021-12-31 C000685 CAMERON,  Campo, Distribution, Unattended 2021-01-012021-12-31 C000685 , ,  4 , 2-4000 KCMIL CU 2021-01-012021-12-31 C000685 Centinela Solar Energy 2 LLC, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 2021-01-012021-03-31 C000685 PROCTOR VALLEY, Bonita, Distribution, Unattended 2021-01-012021-12-31 C000685 CABRILLO, San Diego, Distribution, Unattended 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember DATA FOUNDATION AND REPORTING 2021-01-012021-12-31 C000685 Environmental Program 2020-12-31 C000685 Supply Management, Sempra Energy 2021-01-012021-12-31 C000685 SHORECLIFFS-San Clemente, Distribution, Unattended 2021-01-012021-12-31 C000685 TL605 RECONDUCTOR 2021-01-012021-12-31 C000685 CSolar IV South LLC, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 SONGS Mitigation 2021-12-31 C000685 EL CAJON SUBSTATION 12KV BREAKER REPLACEMENTferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 PENDLETON, Oceanside, Distribution, Unattended 2021-12-31 C000685 WILDFIRE MGMT ASSESSMENT PLATFORM 2021-01-012021-12-31 C000685 A. Electric R, D & D Performed Internally, 2021-01-012021-12-31 C000685 Miscellaneous_2 2021-12-31 C000685 4.150% Series SSS due 2048 2021-01-012021-12-31 C000685 MM San Diego LLC (Miramar RAM), LU, FERC Vol. 10 2021-01-012021-12-31 C000685 UNALLOCATED CONSTRUCTION OVERHEADS & LABOR ACCRUAL 2021-01-012021-12-31 C000685 D. 21-08-030 RESOURCE ADEQUACY PROGRAM 2021-12-31 C000685 Distribution Operation Supv & Engineering_17, Sempra Energy 2021-01-012021-12-31 C000685 Current State Tax Deduction 2021-01-012021-12-31 C000685 GAS Cuyamaca 2021-01-012021-12-31 C000685 Miguel, ,  1S , 2-636 ACSS/AW 2021-01-012021-12-31 C000685 Miguel, , 1S,3, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember TL6916 POLE REPLACEMENT 2021-12-31 C000685 GRANITE SUBSTATION 69KV LOOP-INferc:ElectricUtilityMember 2021-12-31 C000685 TRANSMISSION-OTHER, 358 2021-01-012021-12-31 C000685 Calpine Energy Services LP , SF, FERC Vol. 10 2021-01-012021-12-31 C000685 Deferred Debits, Sempra Energy 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember TL23001 INSULATOR REPLACEMENT 2021-12-31 C000685 SONGS, Transmission, Unattended 2021-01-012021-12-31 C000685 TRANSMISSION-OTHER, 353.4 2021-01-012021-12-31 C000685 Expenses, Except ISO Charge, , , 2021-01-012021-12-31 C000685 KEARNY BATTERY ENERGY STORAGE PROJECTferc:ElectricUtilityMember 2021-12-31 C000685 Business License, Local Tax, CA, 2021 2021-01-012021-12-31 C000685 WARREN CANYON_2, Poway, Distribution, Unattended 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember TL694 WOOD TO STEEL REPLACEMENT 2021-01-012021-12-31 C000685 3.600% Series NNN due 2023 2021-01-012021-12-31 C000685 GAS Palomar 2021-01-012021-12-31 C000685 C724: NEW 12KV CIRCUIT 2021-01-012021-12-31 C000685 Miguel, , 1S,3, 2-605 ACSS/AW 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember TEE MODERNIZATION PROGRAM 2021-12-31 C000685 ferc:UnemploymentTaxMember 2021-12-31 C000685 Vista Energy Storage, SF, FERC Vol. 10 2021-01-012021-12-31 C000685 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Unattended 2021-01-012021-12-31 C000685 SUNNYSIDE, San Diego, Distribution, Unattended 2021-01-012021-12-31 C000685 LOVELAND_1, Z293866, OH, 2021-01-012021-12-31 C000685 TRANSMISSION-SRPL, 352 2021-01-012021-12-31 C000685 D. 21-03-053 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_1 2021-01-012021-12-31 C000685 , Sycamore,  3 , 2-1109 ACAR 2021-01-012021-12-31 C000685 Broker Fees, OS, 2021-01-012021-12-31 C000685 SAMPSON, San Diego, Distribution, Unattended 2021-12-31 C000685 ferc:OtherAllocatedTaxMember 2021-12-31 C000685 J&D Labs Fuel Cell 2021-01-012021-12-31 C000685 DISTRIBUTION, 368.2 2021-01-012021-12-31 C000685 OTAY LAKES, Chula Vista, Distribution, Unattended 2021-01-012021-12-31 C000685 Z119772, , 1W,1S,3, 1-250 MCM CU 2021-01-012021-12-31 C000685 Sales and Use (Note 2), State Tax, CA, 2021 2021-01-012021-12-31 C000685 Business License, Local Tax, CA, 2021 2020-12-31 C000685 A6-TOU 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember SUBSTATION BREAKER AND RELAY 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California Gas Company 2021-01-012021-12-31 C000685 BUTTERFIELD MICROGRIDferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 PURE WATER PROJECTferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 Affiliate Billings, Electric 2021-01-012021-12-31 C000685 Congestion 2021-01-012021-12-31 C000685 Miguel, East County, 1S,3, 2-2156 ACSR 2021-01-012021-12-31 C000685 DISTRIBUTION, E373.20 2021-01-012021-12-31 C000685 SAN LUIS REY-Oceanside, Distribution, Unattended 2021-01-012021-12-31 C000685 ferc:SulfurDioxideMember   Transfers to Miramar 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember 2020-12-31 C000685 Friars, , 4, 2-2500 CU 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember DISTRIBUTION CIRCUIT RELIABILITY CONSTRUCTION 2021-12-31 C000685 (amortization 01/1986 - 12/2023) 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember UG NON-RESIDENTIAL NEW BUSINESS 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember 4% 2021-01-012021-12-31 C000685 NAVAL STATION Switchyard, 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12KV BREAKER REPLACEMENT 2021-01-012021-12-31 C000685 IMPERIAL BEACH_2, Imperial Beach, Distribution, Unattended 2021-12-31 C000685 Sycamore Canyon, , 1S,3, 2-900 ACSS/AW 2021-01-012021-12-31 C000685 ENCINA switchyard, Carlsbad, Transmission, Unattended 2021-01-012021-12-31 C000685 Z293865_1, Z293866, UG, 2021-01-012021-12-31 C000685 Miscellaneous General Expense, Southern California Gas Company 2021-01-012021-12-31 C000685 Maintenance supervision and engineering, Sempra Energy 2021-01-012021-12-31 C000685 East County, Eco Gen 1, 1S, 2-1113 ACSS/AW 2021-01-012021-12-31 C000685 3rd Party Billings, Gasferc:AllocationOfPayrollChargedForClearingAccountsMember 2021-01-012021-12-31 C000685 Theoretical Withdrawal Premium OIL 2021-01-012021-12-31 C000685 WARNERS. Warner Springs, Distribution, Unattended 2021-01-012021-12-31 C000685 D. 21-04-009 WILDFIRE MITIGATION PLANS 2021-12-31 C000685 TRANSMISSION-OTHER, TRANSMISSION-OTHER 2021-01-012021-12-31 C000685 OH PUBLIC SAFETY PROGRAMferc:ElectricUtilityMember 2021-12-31 C000685 Talega, , 3, 1-336.4 ACSR/AW 2021-01-012021-12-31 C000685 , , 2S, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 GLENCLIFF-GC, Distribution, Unattended 2021-01-012021-12-31 C000685 Maricopa West Solar PV LLC , LU, FERC Vol. 10 2021-01-012021-12-31 C000685 Balancing Account Undercollections 2021-01-012021-12-31 C000685 Federalferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 FELICITA,Escondido, Distribution, Unattended 2021-12-31 C000685 MESA HEIGHTS,SanDiego, Distribution, Unattended 2021-12-31 C000685 10% 2021-01-012021-12-31 C000685 2021-01-012021-09-30 C000685 Boulavard, Boulevard East, 4, 2-2500 KCMIL CU 2021-01-012021-12-31 C000685 Other: Net (Increase) Decrease in Prepayments and Other 2021-01-012021-12-31 C000685 BAY BOULEVARD, Transmission, Unattended 2021-12-31 C000685 DIVISION, San Diego, Distribution, Unattended 2021-01-012021-12-31 C000685 D. 21-05-029 WILDFIRE MITIGATION PLANS 2021-01-012021-12-31 C000685 4.300% Series MMM due 2042 2021-12-31 C000685 Clean Energy Alliance, SF, FERC Vol. 10 2021-01-012021-12-31 C000685 Miscellaneous_2 2021-01-012021-12-31 C000685 Line of credit (LOC) fees 2020-12-31 C000685 Unemployment (Note 4), State Tax, CA, 2021 2020-12-31 C000685 TL600 RELIABILITY POLE REPLACEMENTSferc:ElectricUtilityMember 2021-12-31 C000685 PBOP Asset 2021-01-012021-12-31 C000685 GENERAL, 397.7 2021-01-012021-12-31 C000685 OL-1 2021-01-012021-12-31 C000685 DISTRIBUTION, 367 2021-01-012021-12-31 C000685 CALAVO GARDENS, El Cajon, Distribution, Unattended 2021-12-31 C000685 Meter Expenses, Sempra Energy 2021-01-012021-12-31 C000685 Pension Benefits 2020-12-31 C000685 , Batiquitos, 1S, 2-1109 ACAR 2021-01-012021-12-31 C000685 ferc:OtherAdValoremTaxMember 2021-12-31 C000685 ferc:GasUtilityMember State 2020-12-31 C000685 ESCO_1, Escondido, Distribution, Unattended 2021-01-012021-12-31 C000685 2021-12-31 C000685 D. 21-08-013 PUBLIC UTILITY REGULATORY POLICIES 2021-01-012021-12-31 C000685 HFTD OVERHEAD DISTRIBTUION HARDENINGferc:ElectricUtilityMember 2021-12-31 C000685 2019-12-31 C000685 ASH, Escondido, Distribution, Unattended 2021-01-012021-12-31 C000685 WARREN CANYON_1, Poway, Distribution, Unattended 2021-12-31 C000685 , ,  1S , 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 Unemployment (Note 4), Federal Tax, CA, 2021 2021-12-31 C000685 FIBER OPTIC FOR RELAY PROTECTION & TELECOMMUNICATIONferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 Sycamore Energy 1 LLC , LU, FERC Vol. 10 2021-01-012021-12-31 C000685 , Sycamore Canyon,  1S,3 , 2-900 ACSS/AW 2021-01-012021-12-31 C000685 Other Debit or Cr. Items (Describe, details in footnote): 2021-01-012021-12-31 C000685 _1, , 1S,3, 2-1109 ACAR 2021-01-012021-12-31 C000685 D. 21-07-024 ENERGY ACCESS_1 2021-01-012021-12-31 C000685 D. 21-02-025 BUILDING DECARBONIZATION_2 2021-01-012021-12-31 C000685 HEAVY DUTY VEHICLE CHARGING INFRASTRUCTUREferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 Accounting & Finance, Southern California Gas Company 2021-01-012021-12-31 C000685 Environmental Clean-Up 2021-01-012021-12-31 C000685 TRANSMISSION-SRPL, 354 2021-01-012021-12-31 C000685 Cpmpressor Stn Exp, Southern California Gas Company 2021-01-012021-12-31 C000685 Airbus Helicopter Trade Account 2021-01-012021-12-31 C000685 Sales and Use (Note 2), Local Tax, CA, 2021 2021-12-31 C000685 EL CAJON SUBSTATION 12KV BREAKER REPLACEMENTferc:ElectricUtilityMember 2021-12-31 C000685 2000 Energy Crisis Disbursement 2021-01-012021-12-31 C000685 GRANT HILLSan Diego, Distribution, Unattended 2021-01-012021-12-31 C000685 6.000% Series DDD due 2026 2021-12-31 C000685 D. 21-02-020 BUILDING DECARBONIZATION_2 2021-12-31 C000685 D. 21-07-024 ENERGY ACCESS_2 2021-12-31 C000685 CRESTWOODCampo, Distribution, Unattended 2021-12-31 C000685 ferc:OtherUseTaxMember 2021-01-012021-12-31 C000685 ferc:GasUtilityMember State 2021-01-012021-12-31 C000685 Environmental Clean-Up 2021-12-31 C000685 Real Estate & Facilities, Sempra Energy 2021-01-012021-12-31 C000685 DG 2021-01-012021-12-31 C000685 CONDITION BASED MONITORING - CIRCUIT BREAKERSferc:ElectricUtilityMember 2021-12-31 C000685 D. 20-12-039 ENERGY STORAGE PROCUREMENT 2021-01-012021-12-31 C000685 TRANSMISSION-SWPL, 354 2021-01-012021-12-31 C000685 Imperial Valley, Phase Shifting Transformer,  1S , 2-900 ACSS/AW 2021-01-012021-12-31 C000685 D. 21-08-033 ENERGY ACCESS_2 2021-01-012021-12-31 C000685 GRANT HILLSan Diego, Distribution, Unattended 2021-12-31 C000685 Other (Itemized within footnote) 2021-01-012021-12-31 C000685 0 2021-01-012021-12-31 C000685 D. 21-10-008 WILDFIRE MITIGATION PLANS 2021-01-012021-12-31 C000685 WOOD POLE REINFORCEMENTferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 NON-HFTD OVERHEAD EQUIPMENT REPLACEMENT 2021-01-012021-12-31 C000685 TRANSMISSION-SRPL, 359 2021-01-012021-12-31 C000685 Other Debit or Cr. Items (Describe, details in footnote):ferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 , Encina, 1S,3, 2-1109 ACAR 2021-01-012021-12-31 C000685 GENERAL, 392.2 2021-01-012021-12-31 C000685 GRANITE SUBSTATION 12KV BREAKER REPLACEMENTferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 3.750% Series RRR due 2047 2021-01-012021-12-31 C000685 TL628 CABLE REPLACEMENTferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 D. 21-09-033 CLIMATE CHANGE ADAPTATION_2 2021-01-012021-12-31 C000685 OCEANSIDE, Oceanside, Distribution, Unattended 2021-01-012021-12-31 C000685 Other (Itemized within footnote) 2021-01-012021-12-31 C000685 TL691 WOOD TO STEEL REPLACEMENTferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 Real Estate & Facilities, Southern California Gas Company 2021-01-012021-12-31 C000685 Sycamore, , 4, 1-3000 KCMIL CU 2021-01-012021-12-31 C000685 DR 2021-01-012021-12-31 C000685 Cascade Solar LLC, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 NEW SERVICE INSTALLATIONSferc:ElectricUtilityMember 2021-12-31 C000685 FALLBROOK BATTERY ENERGY STORAGE SYSTEM_1ferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 Deferred Taxes Recoverable in Rates 2020-12-31 C000685 Encina Switchyard, , 1S,3, 2-1109 ACAR 2021-01-012021-12-31 C000685 CAPISTRANO, San Juan Capistrano, Distribution, Unattended 2021-01-012021-12-31 C000685 GENERATION HYDROGEN PROJECT 2021-01-012021-12-31 C000685 RAMONA, Ramona, Distribution, Unattended 2021-01-012021-12-31 C000685 D. 21-03-040 ELECTRICITY INTEGRATED RESOURCE 2021-01-012021-12-31 C000685 TRANSMISSION-SWPL, TRANSMISSION-SWPL 2021-01-012021-12-31 C000685 2021-01-012021-12-31 C000685 Other Accounts (Specify, provide details in footnote): 2021-01-012021-12-31 C000685 ferc:GasUtilityMember 0 2021-12-31 C000685 Operation supervision and engineering, Sempra Energy 2021-01-012021-12-31 C000685 D. 21-11-023 RESOURCE ADEQUACY PROGRAM 2021-12-31 C000685 , San Mateo, 1S, 1-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember UG NON-RESIDENTIAL NEW BUSINESS 2021-12-31 C000685 Z874970, Carlton Hills, 1S,3, 1-900 ACSS/AW 2021-01-012021-12-31 C000685 Miscellaneous Transmission Expenses, Southern California Gas Company 2021-01-012021-12-31 C000685 Encina Hub, Calavera Tap, 2W, 1-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 Taxes on Income (Note 3), Federal Tax, CA, 2021 2021-12-31 C000685 Palomar 2021-12-31 C000685 NORTH CITY WEST, San Diego, Distribution, Unattended 2021-12-31 C000685 MIGUEL_2, Bonita, Transmission, Unattended 2021-01-012021-12-31 C000685 OVERSTRESSED BREAKER REPLACEMENTSferc:ElectricUtilityMember 2021-12-31 C000685 DISTRIBUTION SUBSTATION RELIABILITY 2021-01-012021-12-31 C000685 ENCINITAS_1, Encinitas, Distribution, Unattended 2021-01-012021-12-31 C000685 _2, ,  1W,2W,1S,2S,3 , 1-336.4 ACSR/AW 2021-01-012021-12-31 C000685 DISTRIBUTION, 364 2021-01-012021-12-31 C000685 13811, De-Energized, 1S, 1-900 ACSS/AW 2021-01-012021-12-31 C000685 D. 21-05-011 WILDFIRE MITIGATION PLANS 2021-12-31 C000685 SOUTH SAN CLEMENTE, San clemente, Distribution, Unattended 2021-12-31 C000685 D. 21-10-011 TRIENNIAL COST ALLOCATION 2021-01-012021-12-31 C000685 OIL Insurance Limited 2021-01-012021-12-31 C000685 EASTGATE, San Diego, Distribution, Unattended 2021-01-012021-12-31 C000685 ferc:ExciseTaxMember 2021-12-31 C000685 Maintenance of Lines, Sempra Energy 2021-01-012021-12-31 C000685 Fuel Tax, Federal Tax, CA, 2021 2021-12-31 C000685 D. 21-02-017 RESIDENTIAL RATE DESIGN WINDOW 2021-01-012021-12-31 C000685 D. 21-05-025 POWER CHARGE INDIFFERENCE 2021-01-012021-12-31 C000685 FIRE THREAT ZONE UNDERGROUNDING 2021-01-012021-12-31 C000685 Miguel, , 1S, 2-605 ACSS/AW 2021-01-012021-12-31 C000685 Environmental Program 2021-12-31 C000685 TRANSMISSION-SWPL, 356 2021-01-012021-12-31 C000685 GTO Operations Supervision & Engineering, Southern California Gas Company 2021-01-012021-12-31 C000685 , Penasquitos, 1S, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 Capistrano, , 1W, 1-636 ACSR/AW 2021-01-012021-12-31 C000685 Medicare (Note 4), Federal Tax, CA, 2021 2021-01-012021-12-31 C000685 0ferc:NovemberMember 2021-01-012021-12-31 C000685 Sol Orchard 22 LLC (Valley Center 1), LU, FERC Vol. 10 2021-01-012021-12-31 C000685 Common 2021-01-012021-12-31 C000685 AD 2021-01-012021-12-31 C000685 Miscellaneous 2021-01-012021-12-31 C000685 LILAC, Valley Center, Distribution, Unattended 2021-12-31 C000685 , Z189532, 3, 2-400 MCM CU 2021-01-012021-12-31 C000685 MONTGOMERY, Chula Vista, Distribution, Unattended 2021-01-012021-12-31 C000685 Miscellaneous Distribution Expenses, Southern California Gas Company 2021-01-012021-12-31 C000685 San Diego Community Power, SF, FERC Vol. 10 2021-01-012021-12-31 C000685 BAY BOULEVARD, Transmission, Unattended 2021-01-012021-12-31 C000685 D. 21-09-033 CLIMATE CHANGE ADAPTATION_1 2021-12-31 C000685 SYNCHRONIZED PHASOR MEASUREMENT SYSTEMferc:ElectricUtilityMember 2021-12-31 C000685 D. 21-03-038 ELECTRICITY INTEGRATED RESOURCE 2021-01-012021-12-31 C000685 HFTD TIER 2 & 3 CMP POLE REPLACEMENTSferc:ElectricUtilityMember 2021-12-31 C000685 MIGUEL_2, Bonita, Transmission, Unattended 2021-12-31 C000685 Sunrise Wildfire Mitigation 2021-12-31 C000685 Workers Comp Receivable 2020-12-31 C000685 LOVELAND, Alpine, Distribution, Unattended 2021-01-012021-12-31 C000685 , Escondido,  1S,3 , 1-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 JAPANESE MESA, San Clemente, Distribution, Unattended 2021-12-31 C000685 BORDER-, San Diego, Distribution, Unattended 2021-01-012021-12-31 C000685 Sales and Use (Note 2), State Tax, CA, 2021 2020-12-31 C000685 Fed Discrete Taxes 2021-01-012021-12-31 C000685 ferc:OctoberMember 0 2021-01-012021-12-31 C000685 D. 20-12-043 RESIDENTIAL RATE DESIGN WINDOW 2021-01-012021-12-31 C000685 D. 21-03-038 ELECTRICITY INTEGRATED RESOURCE 2021-12-31 C000685 Other (provide details in footnote): 2021-01-012021-12-31 C000685 OTHER PRODUCTION, 345-Palomar 2021-01-012021-12-31 C000685 Expense of NonUtility Operations, Southern California Gas Company 2021-01-012021-12-31 C000685 Cannon_1, Encina Hub, 1S,3, 2-1109 ACAR 2021-01-012021-12-31 C000685 PAT1 2021-01-012021-12-31 C000685 URBAN-, San Diego, Distribution, Unattended 2021-12-31 C000685 OTHER PRODUCTION, 343-Miramar 2021-01-012021-12-31 C000685 EAST COUNTY_1, Boulevard, Transmission, Unattended 2021-12-31 C000685 FERC Electric Tariff, Volume No.11, ER21-675-000 2021-01-012021-12-31 C000685 Sentinel Energy, SF, FERC Vol. 10 2021-01-012021-12-31 C000685 Information Technology, Sempra LNG 2021-01-012021-12-31 C000685 , Penasquitos, 1S,3, 1-636 ACSR/AW 2021-01-012021-12-31 C000685 TL6926 RINCON-VALLEY CENTER POLE REPLACEMENTferc:ElectricUtilityMember 2021-12-31 C000685 Maintenance of other equipment., Sempra Energy 2021-01-012021-12-31 C000685 ferc:OtherUtilityMember Other (Specify) 2020-12-31 C000685 Batiquitos, , 1S, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 SANTEE, Santee, Distribution, Unattended 2021-12-31 C000685 PICO, San Clemente, Distribution, Unattended 2021-01-012021-12-31 C000685 Wildfire Fund AB1054 2020-12-31 C000685 Palomar_1, , 1S, 2-900 ACSS/AW 2021-01-012021-12-31 C000685 Electric / Gas Derivatives 2020-12-31 C000685 FIRE THREAT ZONE COMPLIANCE PROGRAMferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 Deferred Taxes Recoverable in Rates 2021-01-012021-12-31 C000685 BOSTONIA, El Cajon, Distribution, Unattended 2021-12-31 C000685 ferc:StateTaxMember 2020-12-31 C000685 East County, ,  1S,2S , 2-900 ACSS/AW 2021-01-012021-12-31 C000685 Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock 2021-01-012021-12-31 C000685 D. 21-05-025 POWER CHARGE INDIFFERENCE 2021-12-31 C000685 , Santee, 1W,1S, 1-900 ACSS/AW 2021-01-012021-12-31 C000685 ferc:GasUtilityMember Gas 2021-12-31 C000685 , Mission, 4, 1-5000 KCMIL CU ENAMEL 2021-01-012021-12-31 C000685 TELEGRAPH CANYON, Chula Vista, Distribution, Unattended 2021-12-31 C000685 ferc:PropertyTaxMember 2020-12-31 C000685 CORONADO, 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21-12-014 ELECTRICITY INTEGRATED RESOURCE 2021-01-012021-12-31 C000685 TL600 RELIABILITY POLE REPLACEMENTSferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 DISTRIBUTION, E371.00 2021-01-012021-12-31 C000685 Fuel Tax, State Tax, CA, 2021 2020-12-31 C000685 , , 1S,3, 1-400 MCM CU 2021-01-012021-12-31 C000685 TL667 CABLE REPLACEMENTferc:ElectricUtilityMember 2021-12-31 C000685 Pacific Wind Lessee LLC, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 ferc:PropertyTaxMember 2021-12-31 C000685 TL13838 WOOD TO STEEL REPLACEMENTferc:ElectricUtilityMember 2021-12-31 C000685 MINOR PROJECTS (LESS THAN $1,000,000)ferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 SAN CLEMENTE, San clemente, Distribution, Unattended 2021-12-31 C000685 Mitigation Fund 2021-01-012021-12-31 C000685 Calpine Energy Services, SF, FERC Vol. 10 2021-01-012021-12-31 C000685 , GIS Terminal_2, 4, 1-5000 KCMIL CU 2021-01-012021-12-31 C000685 Deferred Taxes Payable in rates 2021-01-012021-12-31 C000685 OTHER PRODUCTION, 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C000685 , Talega, 1W, 1-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 Routine Leak Survey, Southern California Gas Company 2021-01-012021-12-31 C000685 ferc:ElectricOtherFacilitiesMember Other (provide details in footnote): 2021-01-012021-12-31 C000685 CAPISTRANO, San Juan Capistrano, Distribution, Unattended 2021-12-31 C000685 Encina Switchyard, , 1S, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 TIMP-Main Supv & Eng, Southern California Gas Company 2021-01-012021-12-31 C000685 Accounts Payable, Southern California Gas Company 2021-01-012021-12-31 C000685 NEW BUSINESS INFRASTRUCTUREferc:ElectricUtilityMember 2021-12-31 C000685 FIRE THREAT ZONE COMPLIANCE PROGRAM 2021-01-012021-12-31 C000685 POINT LOMA, San Diego, Distribution, Unattended 2021-12-31 C000685 Construction Work in Progress, Southern California Gas Company 2021-01-012021-12-31 C000685 OCOTILLO switchyard, Ocotillo, Transmission, Unattended 2021-01-012021-12-31 C000685 Maintenance / Meters & Hse Reg, Southern California Gas 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BREAKER REPLACEMENT 2021-12-31 C000685 PENASQUITOS_2, San Diego, Transmission, Unattended 2021-01-012021-12-31 C000685 TL673 CABLE REPLACE 2021-01-012021-12-31 C000685 MIGUEL_3, Bonita, Transmission, Unattended 2021-01-012021-12-31 C000685 4.150% Series SSS due 2048 2021-12-31 C000685 Electric / Gas Derivatives 2021-12-31 C000685 Surplus Material 2020-12-31 C000685 Cuyamaca 2021-12-31 C000685 Operation supervision and engineering_1, Sempra Energy 2021-01-012021-12-31 C000685 Other Expenses 2021-01-012021-12-31 C000685 LAS PULGAS_1, JAPANESE MESA, OH, 2021-01-012021-12-31 C000685 TRANSMISSION-SWPL, SUBTOTAL 2021-01-012021-12-31 C000685 , Penasquitos, 3, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 Greenhouse Gas Obligations 2021-01-012021-12-31 C000685 HFTD OVERHEAD DISTRIBTUION HARDENING 2021-01-012021-12-31 C000685 BORREGO MICROGRIDferc:ElectricUtilityMember 2021-12-31 C000685 , , 1S, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMember TL639 POLE REPLACEMENT 2021-12-31 C000685 EL CAJON, El Cajon, Distribution, Unattended 2021-01-012021-12-31 C000685 City of Oceanside (San Francisco Peak Hydro), LU, FERC Vol. 10 2021-01-012021-12-31 C000685 ferc:DirectPayrollDistributionMember 2021-01-012021-12-31 C000685 El Cajon Energy Center (Tolling), LU, FERC Vol. 10 2021-01-012021-12-31 C000685 GENERAL, 397.6 2021-01-012021-12-31 C000685 ferc:DistributionPlantMemberferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 PURE WATER PROJECT 2021-01-012021-12-31 C000685 SAN LUIS REY, Oceanside, , Transmission, Unattended 2021-01-012021-12-31 C000685 ferc:AllocationOfPayrollChargedForClearingAccountsMember 2021-01-012021-12-31 C000685 SANTA YSABEL, Santa Ysabel, Distribution, Unattended 2021-01-012021-12-31 C000685 CARLTON HILLS, Santee, Distribution, Unattended 2021-12-31 C000685 OTHER PRODUCTION, 344-CPEP 2021-01-012021-12-31 C000685 D. 21-10-011 TRIENNIAL COST ALLOCATION 2021-12-31 C000685 Environmental Services, Southern California Gas Company 2021-01-012021-12-31 C000685 ferc:OtherPropertyTaxMember 2021-01-012021-12-31 C000685 (4) Research Support to Others, CPUC and California Energy Commission 2021-01-012021-12-31 C000685 Mitigation Fund 2020-12-31 C000685 Increases (Decreases) in Other Paid-In Capital 2021-01-012021-12-31 C000685 3.320% Series UUU due 2050 2021-01-012021-12-31 C000685 ferc:MiscellaneousOtherTaxMember 2021-01-012021-12-31 C000685 San Diego County Water Authority -Olivenhain-Hodges, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 CAMERON,  Campo, Distribution, Unattended 2021-12-31 C000685 CSolar IV West LLC, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 D. 21-02-018 ENERGY EFFICIENCY ROLLING PORTFOLIO_2 2021-12-31 C000685 Other 2021-01-012021-09-30 C000685 PALOMAR ENERGY CENTER OPERATIONAL ENHANCEMENTS 2021-01-012021-12-31 C000685 20201030-5458, 44134, ER21-320-000 2021-01-012021-12-31 C000685 POWAY, Poway, Distribution, Unattended 2021-12-31 C000685 FERC Proceedings _1 2021-12-31 C000685 Greenhouse Gas Obligations 2021-12-31 C000685 , Tijuana, 3, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 D. 21-05-029 WILDFIRE MITIGATION PLANS 2021-12-31 C000685 _2, , 1S,3, 1-636 ACSR/AW 2021-01-012021-12-31 C000685 C303 RECONDUCTORferc:ElectricUtilityMember 2021-12-31 C000685 Other: Net (Increase) Decrease in Prepayments and Other 2020-01-012020-12-31 C000685 D. 21-05-028 RESIDENTIAL RATE DESIGN WINDOW 2021-12-31 C000685 , ,  1S , 2-1109 ACAR 2021-01-012021-12-31 C000685 DISTRIBUTION, 362.1 2021-01-012021-12-31 C000685 ferc:LocalTaxMemberferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 NLP Valley Center Solar LLC, LU, FERC Vol. 10 2021-01-012021-12-31 C000685 0ferc:SeptemberMember 2021-01-012021-12-31 C000685 ferc:ElectricUtilityMemberferc:ElectricPlantInServiceMember 2020-12-31 C000685 Taxes on Income (Note 3), Federal Tax, CA, 2021 2021-01-012021-12-31 C000685 Other: LTD Issuance Cost 2021-01-012021-12-31 C000685 GAS Desert Star 2021-01-012021-12-31 C000685 PARADISE, San Diego, Distribution, Unattended 2021-12-31 C000685 TL6916 POLE REPLACEMENT 2021-01-012021-12-31 C000685 ferc:CommonUtilityMember 2021-12-31 C000685 Franchise (Note 3), State Tax, CA, 2021 2021-01-012021-12-31 C000685 , Penasquitos, 1S,3, 2-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 Unbilled Revenue 2021-01-012021-12-31 C000685 ferc:SeveranceTaxMember 2021-01-012021-12-31 C000685 VINE, Distribution, Unattended 2021-12-31 C000685 LAGUNA NIGUEL, Laguna Niguel, Distribution, Unattended 2021-01-012021-12-31 C000685 SAN YSIDRO, San Ysidro, Distribution, Unattended 2021-12-31 C000685 (amortization 07/2019-07/2034) 2021-01-012021-12-31 C000685 (1) Research Support to the Electrical, NONE 2021-01-012021-12-31 C000685 Other (Itemized within footnote) 2021-01-012021-12-31 C000685 1.700% Series VVV due 2030 2021-01-012021-12-31 C000685 GENERAL, 395.1 2021-01-012021-12-31 C000685 D. 21-11-026 COST OF CAPITAL_1 2021-01-012021-12-31 C000685 TL615/659 CABLE REPLACEMENT 2021-01-012021-12-31 C000685 DISTRIBUTION, E371.1 2021-01-012021-12-31 C000685 B. External, 2021-01-012021-12-31 C000685 Tax Depreciation on Fixed Assets 2021-01-012021-12-31 C000685 ferc:RealEstateTaxMember 2021-12-31 C000685 TORREY PINES, San Diego, Distribution, Unattended 2021-01-012021-12-31 C000685 D. 21-02-025 BUILDING DECARBONIZATION_2 2021-12-31 C000685 DOE SWITCH REPLACEMENT 2021-01-012021-12-31 C000685 2021-01-012021-06-30 C000685 Pico, , 3, 1-1033.5 ACSR/AW 2021-01-012021-12-31 C000685 WILDFIRE MGMT ASSESSMENT PLATFORMferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 Cannon, Encina Hub, 1S,3, 2-1109 ACAR 2021-01-012021-12-31 C000685 TL674A RECONFIGUREferc:ElectricUtilityMember 2021-01-012021-12-31 C000685 2.950% Series WWW due 2051 (D.08-07-029, D.18-02-012, D.20-04-015 issued August 13, 2021) 2021-01-012021-12-31 iso4217:USD utr:Mcf iso4217:USD utr:MW utr:MWh xbrli:pure utr:MW iso4217:USD iso4217:USD utr:kW utr:kV xbrli:pure utr:mi utr:mi iso4217:USD xbrli:shares utr:Btu utr:kWh utr:kWh xbrli:shares utr:Btu utr:MVA utr:Mcf iso4217:USD utr:kWh iso4217:USD utr:MMBTU
THIS FILING IS
Item 1:
An Initial (Original) Submission
OR
Resubmission No.

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)

San Diego Gas & Electric Company
Year/Period of Report

End of:
2021
/
Q4


INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

  1. Purpose

    FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q) is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
  2. Who Must Submit

    Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities, Licensees, and Others Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).

    Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
    1. one million megawatt hours of total annual sales,
    2. 100 megawatt hours of annual sales for resale,
    3. 500 megawatt hours of annual power exchanges delivered, or
    4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).
  3. What and Where to Submit

    1. Submit FERC Form Nos. 1 and 3-Q electronically through the eCollection portal at https://eCollection.ferc.gov, and according to the specifications in the Form 1 and 3-Q taxonomies.
    2. The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
    3. Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
      Secretary
      Federal Energy Regulatory Commission 888 First Street, NE
      Washington, DC 20426
    4. For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

      The CPA Certification Statement should:
      1. Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and
      2. Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.)

        Schedules
        Pages
        Comparative Balance Sheet 110-113
        Statement of Income 114-117
        Statement of Retained Earnings 118-119
        Statement of Cash Flows 120-121
        Notes to Financial Statements 122-123
    5. The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.

      “In connection with our regular examination of the financial statements of [COMPANY NAME] for the year ended on which we have reported separately under date of [DATE], we have also reviewed schedules [NAME OF SCHEDULES] of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

      Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
    6. Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. Further instructions are found on the Commission’s website at https://www.ferc.gov/ferc-online/ferc-online/frequently-asked-questions-faqs-efilingferc-online.
    7. Federal, State, and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from https://www.ferc.gov/general-information-0/electric-industry-forms.
  4. When to Submit

    FERC Forms 1 and 3-Q must be filed by the following schedule:

    1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
    2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
  5. Where to Send Comments on Public Reporting Burden.

    The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.

    Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

  1. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
  2. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
  3. Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
  4. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
  5. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).
  6. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
  7. For any resubmissions, please explain the reason for the resubmission in a footnote to the data field.
  8. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
  9. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
  10. Schedule specific instructions are found in the applicable taxonomy and on the applicable blank rendered form.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS
  1. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
  2. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

  1. ’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
  2. 'Person' means an individual or a corporation;
  3. 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;
  1. 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......
  1. "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered
  1. 'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.
  1. Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may by rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports shall be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10
"Sec. 309.
  1. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).


FERC FORM NO.
1

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent

San Diego Gas & Electric Company
02 Year/ Period of Report


End of:
2021
/
Q4
03 Previous Name and Date of Change (If name changed during year)

/
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

8330 Century Park Court, San Diego, CA 92123
05 Name of Contact Person

Eric Dalton
06 Title of Contact Person

Regulatory Reporting Manager
07 Address of Contact Person (Street, City, State, Zip Code)

8330 Century Park Court, San Diego, CA 92123
08 Telephone of Contact Person, Including Area Code

(858) 503-5130
09 This Report is An Original / A Resubmission

(1)
An Original

(2)
A Resubmission
10 Date of Report (Mo, Da, Yr)

04/15/2022
Annual Corporate Officer Certification
The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.

01 Name

Valerie Bille
02 Title

VP, Controller and CAO
03 Signature

Valerie Bille
04 Date Signed (Mo, Da, Yr)

04/15/2022
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
LIST OF SCHEDULES (Electric Utility)

Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

Line No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
ScheduleIdentificationAbstract
Identification
1
ScheduleListOfSchedulesAbstract
List of Schedules
2
1
ScheduleGeneralInformationAbstract
General Information
101
2
ScheduleControlOverRespondentAbstract
Control Over Respondent
102
3
ScheduleCorporationsControlledByRespondentAbstract
Corporations Controlled by Respondent
103
4
ScheduleOfficersAbstract
Officers
104
5
ScheduleDirectorsAbstract
Directors
105
6
ScheduleInformationOnFormulaRatesAbstract
Information on Formula Rates
106
7
ScheduleImportantChangesDuringTheQuarterYearAbstract
Important Changes During the Year
108
8
ScheduleComparativeBalanceSheetAbstract
Comparative Balance Sheet
110
9
ScheduleStatementOfIncomeAbstract
Statement of Income for the Year
114
10
ScheduleRetainedEarningsAbstract
Statement of Retained Earnings for the Year
118
12
ScheduleStatementOfCashFlowsAbstract
Statement of Cash Flows
120
12
ScheduleNotesToFinancialStatementsAbstract
Notes to Financial Statements
122
13
ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract
Statement of Accum Other Comp Income, Comp Income, and Hedging Activities
122a
14
ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep
200
15
ScheduleNuclearFuelMaterialsAbstract
Nuclear Fuel Materials
202
16
ScheduleElectricPlantInServiceAbstract
Electric Plant in Service
204
17
ScheduleElectricPropertyLeasedToOthersAbstract
Electric Plant Leased to Others
213
18
ScheduleElectricPlantHeldForFutureUseAbstract
Electric Plant Held for Future Use
214
19
ScheduleConstructionWorkInProgressElectricAbstract
Construction Work in Progress-Electric
216
20
ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract
Accumulated Provision for Depreciation of Electric Utility Plant
219
21
ScheduleInvestmentsInSubsidiaryCompaniesAbstract
Investment of Subsidiary Companies
224
22
ScheduleMaterialsAndSuppliesAbstract
Materials and Supplies
227
23
ScheduleAllowanceInventoryAbstract
Allowances
228
24
ScheduleExtraordinaryPropertyLossesAbstract
Extraordinary Property Losses
230a
25
ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract
Unrecovered Plant and Regulatory Study Costs
230b
26
ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract
Transmission Service and Generation Interconnection Study Costs
231
27
ScheduleOtherRegulatoryAssetsAbstract
Other Regulatory Assets
232
28
ScheduleMiscellaneousDeferredDebitsAbstract
Miscellaneous Deferred Debits
233
29
ScheduleAccumulatedDeferredIncomeTaxesAbstract
Accumulated Deferred Income Taxes
234
30
ScheduleCapitalStockAbstract
Capital Stock
250
31
ScheduleOtherPaidInCapitalAbstract
Other Paid-in Capital
253
32
ScheduleCapitalStockExpenseAbstract
Capital Stock Expense
254b
33
ScheduleLongTermDebtAbstract
Long-Term Debt
256
34
ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax
261
35
ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract
Taxes Accrued, Prepaid and Charged During the Year
262
36
ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract
Accumulated Deferred Investment Tax Credits
266
37
ScheduleOtherDeferredCreditsAbstract
Other Deferred Credits
269
38
ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract
Accumulated Deferred Income Taxes-Accelerated Amortization Property
272
39
ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract
Accumulated Deferred Income Taxes-Other Property
274
40
ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract
Accumulated Deferred Income Taxes-Other
276
41
ScheduleOtherRegulatoryLiabilitiesAbstract
Other Regulatory Liabilities
278
42
ScheduleElectricOperatingRevenuesAbstract
Electric Operating Revenues
300
43
ScheduleRegionalTransmissionServiceRevenuesAbstract
Regional Transmission Service Revenues (Account 457.1)
302
44
ScheduleSalesOfElectricityByRateSchedulesAbstract
Sales of Electricity by Rate Schedules
304
45
ScheduleSalesForResaleAbstract
Sales for Resale
310
46
ScheduleElectricOperationsAndMaintenanceExpensesAbstract
Electric Operation and Maintenance Expenses
320
47
SchedulePurchasedPowerAbstract
Purchased Power
326
48
ScheduleTransmissionOfElectricityForOthersAbstract
Transmission of Electricity for Others
328
49
ScheduleTransmissionOfElectricityByIsoOrRtoAbstract
Transmission of Electricity by ISO/RTOs
331
50
ScheduleTransmissionOfElectricityByOthersAbstract
Transmission of Electricity by Others
332
51
ScheduleMiscellaneousGeneralExpensesAbstract
Miscellaneous General Expenses-Electric
335
52
ScheduleDepreciationDepletionAndAmortizationAbstract
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
336
53
ScheduleRegulatoryCommissionExpensesAbstract
Regulatory Commission Expenses
350
54
ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract
Research, Development and Demonstration Activities
352
55
ScheduleDistributionOfSalariesAndWagesAbstract
Distribution of Salaries and Wages
354
56
ScheduleCommonUtilityPlantAndExpensesAbstract
Common Utility Plant and Expenses
356
57
ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract
Amounts included in ISO/RTO Settlement Statements
397
58
SchedulePurchasesSalesOfAncillaryServicesAbstract
Purchase and Sale of Ancillary Services
398
59
ScheduleMonthlyTransmissionSystemPeakLoadAbstract
Monthly Transmission System Peak Load
400
60
ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract
Monthly ISO/RTO Transmission System Peak Load
400a
61
ScheduleElectricEnergyAccountAbstract
Electric Energy Account
401a
62
ScheduleMonthlyPeakAndOutputAbstract
Monthly Peaks and Output
401b
63
ScheduleSteamElectricGeneratingPlantStatisticsAbstract
Steam Electric Generating Plant Statistics
402
64
ScheduleHydroelectricGeneratingPlantStatisticsAbstract
Hydroelectric Generating Plant Statistics
406
65
SchedulePumpedStorageGeneratingPlantStatisticsAbstract
Pumped Storage Generating Plant Statistics
408
66
ScheduleGeneratingPlantStatisticsAbstract
Generating Plant Statistics Pages
410
0
ScheduleEnergyStorageOperationsLargePlantsAbstract
Energy Storage Operations (Large Plants)
414
67
ScheduleTransmissionLineStatisticsAbstract
Transmission Line Statistics Pages
422
68
ScheduleTransmissionLinesAddedAbstract
Transmission Lines Added During Year
424
69
ScheduleSubstationsAbstract
Substations
426
70
ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract
Transactions with Associated (Affiliated) Companies
429
71
FootnoteDataAbstract
Footnote Data
450
StockholdersReportsAbstract
Stockholders' Reports (check appropriate box)
Stockholders' Reports Check appropriate box:

Two copies will be submitted

No annual report to stockholders is prepared


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept.

Valerie Bille

VP, Controller and CAO

488 8th Ave. San Diego, CA 92101
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.

State of Incorporation:
CA

Date of Incorporation:
1905-04-06

Incorporated Under Special Law:

3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.

(a) Name of Receiver or Trustee Holding Property of the Respondent:

(b) Date Receiver took Possession of Respondent Property:

(c) Authority by which the Receivership or Trusteeship was created:

(d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.

Electric and Natural Gas Service - California
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements?
(1)
Yes

(2)
No


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.
The common stock of San Diego Gas & Electric is owned 100% by Enova Corporation, the common stock of which is owned 100% by Sempra Energy.


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
CORPORATIONS CONTROLLED BY RESPONDENT
  1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
  2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved.
  3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
  1. See the Uniform System of Accounts for a definition of control.
  2. Direct control is that which is exercised without interposition of an intermediary.
  3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
  4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.
NameOfCompanyControlledByRespondent
Name of Company Controlled
(a)
CompanyControlledByRespondentKindOfBusinessDescription
Kind of Business
(b)
VotingStockOwnedByRespondentPercentage
Percent Voting Stock Owned
(c)
FootnoteReferences
Footnote Ref.
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
OFFICERS
  1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions.
  2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.
OfficerTitle
Title
(a)
OfficerName
Name of Officer
(b)
OfficerSalary
Salary for Year
(c)
DateOfficerIncumbencyStarted
Date Started in Period
(d)
DateOfficerIncumbencyEnded
Date Ended in Period
(e)
1
Chief Executive Officer
Winn, Caroline A.
600,000
2
President and Chief Financial Officer
Folkmann, Bruce A.
463,500
3
Vice President, Chief Accounting Officer, Treasurer, Controller
Bille, Valerie A.
242,400
4
Senior Vice President, General Counsel, Chief Risk Officer
Day, Diana L.
366,700
5
Corporate Secretary
Robinson, April R.
259,020


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
DIRECTORS
  1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), name and abbreviated titles of the directors who are officers of the respondent.
  2. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.
NameAndTitleOfDirector
Name (and Title) of Director
(a)
PrincipalBusinessAddress
Principal Business Address
(b)
MemberOfTheExecutiveCommittee
Member of the Executive Committee
(c)
ChairmanOfTheExecutiveCommittee
Chairman of the Executive Committee
(d)
1
Robert J. Borthwick, Director (1)
San Diego, CA
2
Erbin B. Keith, Director (1)
San Diego, CA
3
Trevor I. Mihalik, Director (1)(2)
San Diego, CA
4
Kevin C. Sagara, Director and Non-executive Chairman(1)
San Diego, CA
5
Caroline A. Winn, Director and Chief Executive Officer
San Diego, CA


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
INFORMATION ON FORMULA RATES
Does the respondent have formula rates?
Yes

No
  1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.
RateScheduleTariffNumber
FERC Rate Schedule or Tariff Number
(a)
ProceedingDocketNumber
FERC Proceeding
(b)
1
FERC Electric Tariff, Volume No.11
ER21-301-000
2
FERC Electric Tariff, Volume No.11
ER21-526-000
3
FERC Electric Tariff, Volume No.11
ER21-617-000
4
FERC Electric Tariff, Volume No.11
ER21-675-000
5
FERC Electric Tariff, Volume No.11
ER21-320-000
6
FERC Electric Tariff, Volume No.11
ER21-243-000


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?
Yes

No (Checked by default - Not explicitly defined)
  1. If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.
AccessionNumber
Accession No.
(a)
DocumentDate
Document Date / Filed Date
(b)
DocketNumber
Docket No.
(c)
DescriptionOfFiling
Description
(d)
RateScheduleTariffNumber
Formula Rate FERC Rate Schedule Number or Tariff Number
(e)
1
11/02/2020
ER21-301-000
2021 Transmission Revenue Balancing Account Adjustment ("TRBAA") Filing
FERC Electric Tariff, Volume No.11
2
12/01/2020
ER21-526-000
TO5 Cycle 3 Formula Rate Tariff Filing
FERC Electric Tariff, Volume No.11
3
12/10/2020
ER21-617-000
2021 Transmission Access Charge Balancing Account, Adjustment ("TACBAA") Filing
FERC Electric Tariff, Volume No.11
4
12/17/2020
ER21-675-000
2021 Reliability Service Balancing Account ("RSBA") Filing
FERC Electric Tariff, Volume No.11
5
10/30/2020
ER21-320-000
Appendix XII Cycle 3 Formula Rate Filing
FERC Electric Tariff, Volume No.11
6
10/29/2020
ER21-243-000
Appendix X Cycle 9 Formula Rate Filing
FERC Electric Tariff, Volume No.11


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
INFORMATION ON FORMULA RATES - Formula Rate Variances
  1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1.
  2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1.
  3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
  4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.
PageNumberOfFormulaRateVariances
Page No(s).
(a)
ScheduleOfFormulaRateVariances
Schedule
(b)
ColumnOfFormulaRateVariances
Column
(c)
LineNumberOfFormulaRateVariances
Line No.
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.

  1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact.
  2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization.
  3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission.
  4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization.
  5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
  6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee.
  7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
  8. State the estimated annual effect and nature of any important wage scale changes during the year.
  9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year.
  10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Pages 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest.
  11. (Reserved.)
  12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
  13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
  14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
On 05/26/2021, the City of San Diego City Council voted to approve new gas and electric franchise agreements with SDG&E. Per the requirements of the City of San Diego City Charter, a second reading and vote was held on 06/08/2021, where a supermajority of the San Diego City Council confirmed their initial vote to approve these new agreements. The agreement is effective as of July 2021. This recent Council action is the subject of ongoing litigation.
None
None
SDG&E amended its current License for space located on Beech St., extending the term six additional months, expiring 06/30/2022. Written notice was provided to Landlord on 12/30/2021 to vacate hangar 3 located at Joe Crosson Dr. effective 01/31/2022.
In the first quarter of 2021, there were no notable changes to the Transmission System.
In the second quarter of 2021, notable changes to the Transmission System included:
TL654
Conductor changed from 1-750 CU to 1-1033.5 ACSR/AW (MS RACK to Z91103)
Conductor changed from 1-250-CU B.S to 1-750 CU B.S (Z2153273111 to STA F RACK)

TL13816
New substation San Juan Capistrano added
Conductor 1-3000 KCMIL CU is added from SJC 138kv GIS to Z125642 (577 ft; 0.1 mile)
Conductor 1-1033.5 ACSR/AW is added from Z125652 to Z31482 (700 ft; 0.13 miles)
Conductor 1-1033.5 ACSR/AW is removed from CP Rack to Z125642 (around 650 ft; 0.12
mile). Conductor is removed from Z125642 to Z31482 (around 750 ft; .14 mile)
In the third quarter of 2021, notable changes to the Transmission System included:
TL6988 [Valley Center - Terra Gen]
New tie line is energized on 08/03/2021
Conductor added 1-3500 KCMIL AL (.31 miles)

TL6957 [Loveland – Barrett]
Loveland by SWAP project WO 2989040.
LL Rack to Z293865, conductor added 1-636 ACSS/AW (0.06 miles)
From Z293865 to Z293866, conductor added 1-3000 KCMIL CU (0.075 miles)

TL6914 [Los Coches – Loveland]
Loveland by SWAP project WO2989040
From Z293865 -Z293866, conductor added 1-3000 KCMIL CU (0.075 miles)

TL648 [Rancho Carmel – Poway]
Replace cable pole and UG cable at RCL sub.
RCL RACK - Z812075, conductor added 1-3000 KCMIL CU (.12 miles). Old conductor removed 1-1750 KCMIL AL (.10 miles)

TL616 [Rancho Santa Fe – Artesian Ranch – Lake Hodges Metering Sub]
Artesian 230kv expansion project. Re-route from SF -BE - LHP station to SF-ARR-LHM SUB. Substation
name change Artesian Sub -> Artesian Ranch sub; Lake Hodges Pump sta. -> lake Hodges Metering sub.
From Z611159 to Z61119, conductor removed 1-636 ACSR/AW (3 miles).
From Z611199 to Z163663, conductor removed 1-1033.5 ACSR/AW (1.45 miles)
From Z163663 to BE rack, conductor removed 1-1750 KCMIL AL (.05 miles)
From Z611159 to Z254619, conductor added 1-636-ACSR/AW (2 miles);
From Z254619 to ARR rack, conductor added 1-3000 KCMIL CU (.18 miles)

TL6974 [Artesian Ranch – Bernardo Sub]
New tie line is energized 10/13/2021
ARR RACK to Z254404, conductor added 1-3000 KCMIL CU (.15 miles)
Z254404 to Z254617, conductor added 1-636 INVAR (2.15 miles)
Z254617 to BE rack, conductor added 1-3000 KCMIL CU (.13 miles)
In the fourth quarter of 2021, notable changes to the Transmission System included:
TL23069 [DREW SWITCHARD – DW GEN 7]
TL23069 newly energized 11/16/21. 1-1250 KCMIL AL is added from Drew Rack to DW GEN 7 755ft (.14 miles) WO# 5986201

TL692 [LAS PULGAS – JAPANESE MESA]
Wood to steel and reconductor (WO# 2981410) Remove old conductor from LP rack to JA Rack 1-1/0 CU B.S. (6.66 miles) Add new conductor from LP rack to JA rack 1-636 ACSR/AW (6.65 miles)
There were no important changes to the distribution system.
During the first quarter of 2021, SDG&E issued commercial paper with an average daily balance of $25.8 million and a maximum outstanding balance of $156.8 million. The quarter-end balance was $129.9 million.
On 03/12/2021, SDG&E paid off the $200 million 364-day term loan.
During the second quarter of 2021, SDG&E issued commercial paper with an average daily balance of $353.9 million and a maximum outstanding balance of $473 million. The quarter-end balance was $437.5 million.
During the third quarter of 2021, SDG&E issued commercial paper with an average daily balance of $115.9 million and a maximum outstanding balance of $388 million. The quarter-end balance was $0 million. In addition, SDG&E borrowed $375 million under a 364-day term loan, maturing 06/27/2022.
During the third quarter of 2021, on 08/13/2021, SDG&E issued $750 million of 2.950% Green First Mortgage Bonds, Series WWW, due 08/15/2051. In addition, on 08/16/2021, SDG&E paid off $350 million of 3.000% First Mortgage Bonds, Series JJJ.
During the fourth quarter of 2021, SDG&E issued commercial paper with an average daily balance of $174.8 million and a maximum outstanding balance of $400.8 million. The year‐end balance was $400.8 million.
None
On 09/01/2021, SDG&E employees represented by the International Brotherhood of Electrical Workers (IBEW) Local 465 received a negotiated base rate increase of 3.75%, affecting 1471 employees:
Total annualized base wages for represented employees in 2021 is $1.43 million above 2020 base wages.
Total annualized wages for represented employees including overtime in 2021 is $1.41 million above 2020 wages including overtime.
Total annualized wage increases were lower due to minimal time-and-one-half costs as a continuing effect of temporary wage concessions made related to the 2020 Pandemic Plan.
Total annualized wage increases were lower due to a decrease in double time pay related to the scheduled 16-hour workday concession within the 2020 Pandemic Plan
On 09/03/2021, SDG&E reached agreement with IBEW Local 465 on the Lineman Attraction and Retention Letter of Understanding. The intent of the agreement is to attract and retain qualified Journeyman Lineman to SDGE. Approximately 235 electric-side employees each received a retention payment of $22k on 10/27/2021. Total overall cost of this payment, the first of two such payments, was $5.17 million.
Please refer to the Legal Proceedings sections of the Notes to the Financial Statements on page 123.56.
None
Please refer to the Notes to the Financial Statements beginning on page 123.1.
Changes in Officers:
NameTitleEffective Date
Kevin C. GeraghtyChief Safety Officer (in addition to existing title of Senior Vice President – Electric Operations)Appointed, 01/01/2021
Eugene W. MitchellVice President – External AffairsResigned, 06/25/2021
Scott B. CriderChief Customer Officer to Senior Vice President of Customer Services and External AffairsChanged, 06/26/2021
Estela M. de LlanosVice President – Clean Transportation, Sustainability and Chief Environmental Officer to Vice President of Energy Procurement and Sustainability; designated Chief Environmental Officer and Chief Sustainability OfficerChanged, 07/10/2021
Miguel RomeroVice President – Energy Supply to Vice President of Advanced Energy InnovationChanged, 07/10/2021


Changes in Directors:

NameTitleEffective Date
Trevor I. MihalikDirectorResigned, 03/23/2021
There have been no material changes in SDG&E's stock ownership or voting power.
N/A


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1
UtilityPlantAbstract
UTILITY PLANT
2
UtilityPlant
Utility Plant (101-106, 114)
200
25,093,206,634
22,911,869,746
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200
1,670,246,956
1,699,907,204
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Enter Total of lines 2 and 3)
26,763,453,590
24,611,776,950
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)
200
(a)
8,253,275,451
7,688,614,673
6
UtilityPlantNet
Net Utility Plant (Enter Total of line 4 less 5)
18,510,178,139
16,923,162,277
7
NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication
Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)
202
8
NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9
NuclearFuelAssembliesInReactorMajorOnly
Nuclear Fuel Assemblies in Reactor (120.3)
10
SpentNuclearFuelMajorOnly
Spent Nuclear Fuel (120.4)
11
NuclearFuelUnderCapitalLeases
Nuclear Fuel Under Capital Leases (120.6)
12
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies
(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)
202
13
NuclearFuelNet
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14
UtilityPlantAndNuclearFuelNet
Net Utility Plant (Enter Total of lines 6 and 13)
18,510,178,139
16,923,162,277
15
OtherElectricPlantAdjustments
Utility Plant Adjustments (116)
16
GasStoredUndergroundNoncurrent
Gas Stored Underground - Noncurrent (117)
17
OtherPropertyAndInvestmentsAbstract
OTHER PROPERTY AND INVESTMENTS
18
NonutilityProperty
Nonutility Property (121)
6,003,644
6,027,761
19
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Prov. for Depr. and Amort. (122)
326,050
326,050
20
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
21
InvestmentInSubsidiaryCompanies
Investment in Subsidiary Companies (123.1)
224
23
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
228
110,647,029
83,449,123
24
OtherInvestments
Other Investments (124)
25
SinkingFunds
Sinking Funds (125)
26
DepreciationFund
Depreciation Fund (126)
27
AmortizationFundFederal
Amortization Fund - Federal (127)
28
OtherSpecialFunds
Other Special Funds (128)
1,011,945,076
1,018,560,122
29
SpecialFunds
Special Funds (Non Major Only) (129)
30
DerivativeInstrumentAssetsLongTerm
Long-Term Portion of Derivative Assets (175)
52,855,769
96,188,239
31
DerivativeInstrumentAssetsHedgesLongTerm
Long-Term Portion of Derivative Assets - Hedges (176)
32
OtherPropertyAndInvestments
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
1,181,125,468
1,203,899,195
33
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
34
CashAndWorkingFunds
Cash and Working Funds (Non-major Only) (130)
35
Cash
Cash (131)
24,919,379
261,589,340
36
SpecialDeposits
Special Deposits (132-134)
37
WorkingFunds
Working Fund (135)
500
38
TemporaryCashInvestments
Temporary Cash Investments (136)
39
NotesReceivable
Notes Receivable (141)
40
CustomerAccountsReceivable
Customer Accounts Receivable (142)
690,440,956
545,017,728
41
OtherAccountsReceivable
Other Accounts Receivable (143)
85,822,400
142,671,640
42
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
44,281,142
55,474,405
43
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
44
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Assoc. Companies (146)
309,614
45
FuelStock
Fuel Stock (151)
227
46
FuelStockExpensesUndistributed
Fuel Stock Expenses Undistributed (152)
227
47
Residuals
Residuals (Elec) and Extracted Products (153)
227
48
PlantMaterialsAndOperatingSupplies
Plant Materials and Operating Supplies (154)
227
132,881,569
141,897,325
49
Merchandise
Merchandise (155)
227
50
OtherMaterialsAndSupplies
Other Materials and Supplies (156)
227
51
NuclearMaterialsHeldForSale
Nuclear Materials Held for Sale (157)
202/227
52
AllowanceInventoryAndWithheld
Allowances (158.1 and 158.2)
228
123,916,690
196,438,887
53
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
228
110,647,029
83,449,123
54
StoresExpenseUndistributed
Stores Expense Undistributed (163)
227
55
GasStoredCurrent
Gas Stored Underground - Current (164.1)
318,197
371,661
56
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
10,519
6,960
57
Prepayments
Prepayments (165)
(b)
157,657,818
(c)
125,338,625
58
AdvancesForGas
Advances for Gas (166-167)
59
InterestAndDividendsReceivable
Interest and Dividends Receivable (171)
2,426,084
2,463,633
60
RentsReceivable
Rents Receivable (172)
61
AccruedUtilityRevenues
Accrued Utility Revenues (173)
85,445,637
83,866,636
62
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
32,854,971
32,679,971
63
DerivativeInstrumentAssets
Derivative Instrument Assets (175)
111,235,687
152,068,927
64
DerivativeInstrumentAssetsLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets (175)
52,855,769
96,188,239
65
DerivativeInstrumentAssetsHedges
Derivative Instrument Assets - Hedges (176)
66
DerivativeInstrumentAssetsHedgesLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67
CurrentAndAccruedAssets
Total Current and Accrued Assets (Lines 34 through 66)
1,240,145,967
1,449,609,680
68
DeferredDebitsAbstract
DEFERRED DEBITS
69
UnamortizedDebtExpense
Unamortized Debt Expenses (181)
44,096,807
39,351,544
70
ExtraordinaryPropertyLosses
Extraordinary Property Losses (182.1)
230a
71
UnrecoveredPlantAndRegulatoryStudyCosts
Unrecovered Plant and Regulatory Study Costs (182.2)
230b
72
OtherRegulatoryAssets
Other Regulatory Assets (182.3)
232
2,592,280,895
2,398,495,226
73
PreliminarySurveyAndInvestigationCharges
Prelim. Survey and Investigation Charges (Electric) (183)
311,787
1,338,961
74
PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges
Preliminary Natural Gas Survey and Investigation Charges 183.1)
75
OtherPreliminarySurveyAndInvestigationCharges
Other Preliminary Survey and Investigation Charges (183.2)
76
ClearingAccounts
Clearing Accounts (184)
75,907
195,364
77
TemporaryFacilities
Temporary Facilities (185)
808,960
69,702
78
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
371,285,065
426,356,105
79
DeferredLossesFromDispositionOfUtilityPlant
Def. Losses from Disposition of Utility Plt. (187)
80
ResearchDevelopmentAndDemonstrationExpenditures
Research, Devel. and Demonstration Expend. (188)
352
81
UnamortizedLossOnReacquiredDebt
Unamortized Loss on Reaquired Debt (189)
6,471,198
7,746,378
82
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234
121,184,972
108,426,484
83
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
84
DeferredDebits
Total Deferred Debits (lines 69 through 83)
3,136,515,591
2,981,589,036
85
AssetsAndOtherDebits
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
24,067,965,165
22,558,260,188


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking
Accumulated Provision for Depreciation & Amortization Classified
under FERC Seven Factor Test
In Accordance with Guidelines in FERC Order 888

Accumulated Provision
Electric
Intangible Plant 173,963,956 
Steam Production Plant 305,885,272 
Other Production Plant 272,588,028 
Transmission Plant 1,635,135,373 
Distribution Plant 3,606,168,212 
General Plant 219,537,534 
Ratemaking Electric 6,213,278,375 
Nuclear Decommissioning 1,011,036,365 
ASC 410 (FAS 143 and FIN 47) - Electric (1,018,731,937)
Capital Leases A/D 90,279,107 
Leased to Others- Citizens A/D (Sunrise) 29,238,086 
Leased to Others- Citizens A/D (SX-PQ) 2,234,053 
Cuyamaca Permanent Adjustment 17,855,747 
Total Electric 6,345,189,796 
Ratemaking Gas 1,161,217,848 
FIN 47 - Gas (215,090,648)
Total Gas 946,127,200 
Ratemaking Common 857,931,943 
FIN 47 - Common 2,922,489 
Capital Lease A/D 101,104,023 
Total Common 961,958,455 
Total Accumulated Provision EOQ 12/2021 8,253,275,451 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production 293,178,925 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production 284,106,681 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant 1,544,320,791 
(b) Concept: Prepayments
The 13-month Average Electric Prepayments for 2021 is $104,600,472.
(c) Concept: Prepayments
The 13-month Average Electric Prepayments for 2020 is $93,697,406.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1
ProprietaryCapitalAbstract
PROPRIETARY CAPITAL
2
CommonStockIssued
Common Stock Issued (201)
250
291,458,395
291,458,395
3
PreferredStockIssued
Preferred Stock Issued (204)
250
4
CapitalStockSubscribed
Capital Stock Subscribed (202, 205)
5
StockLiabilityForConversion
Stock Liability for Conversion (203, 206)
6
PremiumOnCapitalStock
Premium on Capital Stock (207)
591,282,978
591,282,978
7
OtherPaidInCapital
Other Paid-In Capital (208-211)
253
802,165,368
802,165,368
8
InstallmentsReceivedOnCapitalStock
Installments Received on Capital Stock (212)
252
9
DiscountOnCapitalStock
(Less) Discount on Capital Stock (213)
254
10
CapitalStockExpense
(Less) Capital Stock Expense (214)
254b
24,605,640
24,605,640
11
RetainedEarnings
Retained Earnings (215, 215.1, 216)
118
6,598,399,584
6,079,146,682
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118
13
ReacquiredCapitalStock
(Less) Reaquired Capital Stock (217)
250
14
NoncorporateProprietorship
Noncorporate Proprietorship (Non-major only) (218)
15
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
122(a)(b)
10,117,040
10,034,102
16
ProprietaryCapital
Total Proprietary Capital (lines 2 through 15)
8,248,583,645
7,729,413,681
17
LongTermDebtAbstract
LONG-TERM DEBT
18
Bonds
Bonds (221)
256
6,417,859,000
6,053,573,000
19
ReacquiredBonds
(Less) Reaquired Bonds (222)
256
20
AdvancesFromAssociatedCompanies
Advances from Associated Companies (223)
256
21
OtherLongTermDebt
Other Long-Term Debt (224)
256
22
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
23
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Debit (226)
16,893,710
13,172,642
24
LongTermDebt
Total Long-Term Debt (lines 18 through 23)
6,400,965,290
6,040,400,358
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases - Noncurrent (227)
1,400,890,005
1,324,389,008
27
AccumulatedProvisionForPropertyInsurance
Accumulated Provision for Property Insurance (228.1)
28
AccumulatedProvisionForInjuriesAndDamages
Accumulated Provision for Injuries and Damages (228.2)
24,801,946
27,160,254
29
AccumulatedProvisionForPensionsAndBenefits
Accumulated Provision for Pensions and Benefits (228.3)
29,490,029
98,468,088
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
1
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
32
LongTermPortionOfDerivativeInstrumentLiabilities
Long-Term Portion of Derivative Instrument Liabilities
11,316,894
42,363,865
33
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
Long-Term Portion of Derivative Instrument Liabilities - Hedges
34
AssetRetirementObligations
Asset Retirement Obligations (230)
889,835,240
875,839,212
35
OtherNoncurrentLiabilities
Total Other Noncurrent Liabilities (lines 26 through 34)
2,356,334,114
2,368,220,426
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
NotesPayable
Notes Payable (231)
775,767,324
200,000,000
38
AccountsPayable
Accounts Payable (232)
631,812,212
593,050,722
39
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
40
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
96,613,566
63,664,468
41
CustomerDeposits
Customer Deposits (235)
39,847,594
65,802,220
42
TaxesAccrued
Taxes Accrued (236)
262
9,883,625
(a)
14,595,365
43
InterestAccrued
Interest Accrued (237)
50,435,589
46,363,708
44
DividendsDeclared
Dividends Declared (238)
45
MaturedLongTermDebt
Matured Long-Term Debt (239)
46
MaturedInterest
Matured Interest (240)
47
TaxCollectionsPayable
Tax Collections Payable (241)
9,116,331
9,398,357
48
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
237,466,246
302,751,975
49
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
56,606,669
52,796,607
50
DerivativesInstrumentLiabilities
Derivative Instrument Liabilities (244)
32,605,788
75,094,995
51
LongTermPortionOfDerivativeInstrumentLiabilities
(Less) Long-Term Portion of Derivative Instrument Liabilities
11,316,894
42,363,865
52
DerivativeInstrumentLiabilitiesHedges
Derivative Instrument Liabilities - Hedges (245)
53
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54
CurrentAndAccruedLiabilities
Total Current and Accrued Liabilities (lines 37 through 53)
1,928,838,050
1,381,154,552
55
DeferredCreditsAbstract
DEFERRED CREDITS
56
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
119,826,334
111,420,524
57
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
266
13,106,071
13,377,869
58
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
59
OtherDeferredCredits
Other Deferred Credits (253)
269
444,594,052
431,442,573
60
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
2,169,772,983
2,357,732,274
61
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reaquired Debt (257)
62
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accum. Deferred Income Taxes-Accel. Amort.(281)
272
63
AccumulatedDeferredIncomeTaxesOtherProperty
Accum. Deferred Income Taxes-Other Property (282)
1,944,133,637
1,834,966,327
64
AccumulatedDeferredIncomeTaxesOther
Accum. Deferred Income Taxes-Other (283)
441,810,989
290,131,604
65
DeferredCredits
Total Deferred Credits (lines 56 through 64)
5,133,244,066
5,039,071,171
66
LiabilitiesAndOtherCredits
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)
24,067,965,165
22,558,260,188


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: TaxesAccrued
Note 1:
Ad Valorem taxes are allocated based on type of assets in each taxing jurisdiction.

Note 2:
Sales and Use taxes are allocated based on the Common Allocation Factor.

Sales and Use tax adjustments in column "f" are to adjust carry forward balances from last year.

Note 3:
State and Franchise Tax and Federal Income Tax are charged to departments based on total taxable income generated by each department.

Note 4:
Retirement, Unemployment, and Medicare taxes are charged to departments as a percentage of total taxable labor charged.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
STATEMENT OF INCOME

Quarterly

  1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
  2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
  3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter.
  4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter.
  5. If additional columns are needed, place them in a footnote.

Annual or Quarterly if applicable

  1. Do not report fourth quarter data in columns (e) and (f)
  2. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in a similar manner to a utility department. Spread the amount(s) over Lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
  3. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
  4. Use page 122 for important notes regarding the statement of income for any account thereof.
  5. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
  6. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts.
  7. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122.
  8. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
  9. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
  10. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.
Title of Account
(a)
(Ref.) Page No.
(b)
Total Current Year to Date Balance for Quarter/Year
(c)
Total Prior Year to Date Balance for Quarter/Year
(d)
Current 3 Months Ended - Quarterly Only - No 4th Quarter
(e)
Prior 3 Months Ended - Quarterly Only - No 4th Quarter
(f)
Electric Utility Current Year to Date (in dollars)
(g)
Electric Utility Previous Year to Date (in dollars)
(h)
Gas Utiity Current Year to Date (in dollars)
(i)
Gas Utility Previous Year to Date (in dollars)
(j)
Other Utility Current Year to Date (in dollars)
(k)
Other Utility Previous Year to Date (in dollars)
(l)
1
UtilityOperatingIncomeAbstract
UTILITY OPERATING INCOME
2
OperatingRevenues
Operating Revenues (400)
300
(a)
6,060,135,745
(f)
5,716,764,976
5,212,753,006
5,015,890,723
841,518,933
697,643,488
(j)
5,863,806
(n)
3,230,765
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
320
(b)
3,491,009,710
(g)
3,237,591,294
2,971,678,731
2,824,080,272
521,624,560
416,891,085
(k)
2,293,581
(o)
3,380,063
5
MaintenanceExpense
Maintenance Expenses (402)
320
272,403,394
291,139,577
239,806,965
261,193,755
32,596,428
29,945,822
6
DepreciationExpense
Depreciation Expense (403)
336
755,566,306
685,671,419
659,495,924
603,293,250
91,478,822
78,484,751
(l)
4,591,560
(p)
3,893,418
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336
109,656,852
93,924,593
86,569,957
73,801,234
23,086,894
20,123,359
9
AmortizationOfElectricPlantAcquisitionAdjustments
Amort. of Utility Plant Acq. Adj. (406)
336
15,744
15,744
15,744
15,744
10
AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11
AmortizationOfConversionExpenses
Amort. of Conversion Expenses (407.2)
12
RegulatoryDebits
Regulatory Debits (407.3)
4,676,982
3,801,994
2,856,130
2,290,749
1,820,851
1,511,245
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262
205,954,128
186,629,503
174,916,236
158,923,105
29,900,883
26,784,120
(m)
1,137,009
(q)
922,278
15
IncomeTaxesOperatingIncome
Income Taxes - Federal (409.1)
262
46,370,869
133,332,973
53,377,736
130,986,812
7,006,866
2,346,161
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes - Other (409.1)
262
18,234,485
39,767,865
22,323,632
41,331,754
4,089,148
1,563,889
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision for Deferred Income Taxes (410.1)
234, 272
341,570,424
259,864,642
311,685,673
237,832,617
29,884,752
22,032,025
18
ProvisionForDeferredIncomeTaxesCreditOperatingIncome
(Less) Provision for Deferred Income Taxes-Cr. (411.1)
234, 272
194,599,724
229,531,073
181,263,576
210,267,707
13,336,147
19,263,366
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adj. - Net (411.4)
266
271,798
1,050,480
271,798
215,516
1,265,996
20
GainsFromDispositionOfPlant
(Less) Gains from Disp. of Utility Plant (411.6)
21
LossesFromDispositionOfServiceCompanyPlant
Losses from Disp. of Utility Plant (411.7)
22
GainsFromDispositionOfAllowances
(Less) Gains from Disposition of Allowances (411.8)
23
LossesFromDispositionOfAllowances
Losses from Disposition of Allowances (411.9)
24
AccretionExpense
Accretion Expense (411.10)
25
UtilityOperatingExpenses
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)
5,050,587,372
4,701,158,051
4,341,191,354
4,123,697,101
705,961,029
576,025,317
3,434,988
1,435,633
27
NetUtilityOperatingIncome
Net Util Oper Inc (Enter Tot line 2 less 25)
1,009,548,373
1,015,606,925
871,561,652
892,193,622
135,557,904
121,618,171
2,428,818
1,795,132
28
OtherIncomeAndDeductionsAbstract
Other Income and Deductions
29
OtherIncomeAbstract
Other Income
30
NonutilityOperatingIncomeAbstract
Nonutilty Operating Income
31
RevenuesFromMerchandisingJobbingAndContractWork
Revenues From Merchandising, Jobbing and Contract Work (415)
32
CostsAndExpensesOfMerchandisingJobbingAndContractWork
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33
RevenuesFromNonutilityOperations
Revenues From Nonutility Operations (417)
34
ExpensesOfNonutilityOperations
(Less) Expenses of Nonutility Operations (417.1)
9,029,242
6,934,453
35
NonoperatingRentalIncome
Nonoperating Rental Income (418)
37,363
38,948
36
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings of Subsidiary Companies (418.1)
119
37
InterestAndDividendIncome
Interest and Dividend Income (419)
7,183,019
13,668,960
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
(c)
81,462,879
(h)
79,095,805
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
90,738
411,200
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
2,015,252
41
OtherIncome
TOTAL Other Income (Enter Total of lines 31 thru 40)
81,760,009
86,280,460
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
250,048
250,048
45
Donations
Donations (426.1)
16,572,860
13,530,965
46
LifeInsurance
Life Insurance (426.2)
7,593,458
7,555,514
47
Penalties
Penalties (426.3)
259,137
5,587,200
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Exp. for Certain Civic, Political & Related Activities (426.4)
4,092,624
7,169,979
49
OtherDeductions
Other Deductions (426.5)
37,912,963
39,572,224
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
51,494,174
58,554,902
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262
843,356
766,762
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262
11,607,392
12,613,256
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262
5,359,962
5,822,969
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Inc. Taxes (410.2)
234, 272
7,695,860
7,765,578
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Cr. (411.2)
234, 272
1,258,307
1,315,333
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adj.-Net (411.5)
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
9,686,445
11,219,218
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
39,952,280
38,944,776
61
InterestChargesAbstract
Interest Charges
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
237,653,596
233,778,584
63
AmortizationOfDebtDiscountAndExpense
Amort. of Debt Disc. and Expense (428)
4,408,152
4,107,085
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reaquired Debt (428.1)
1,275,181
1,449,784
65
AmortizationOfPremiumOnDebtCredit
(Less) Amort. of Premium on Debt-Credit (429)
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Assoc. Companies (430)
68
OtherInterestExpense
Other Interest Expense (431)
11,190,738
15,223,253
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
(d)
24,279,916
(i)
24,499,867
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
230,247,751
230,058,839
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
819,252,902
824,492,862
72
ExtraordinaryItemsAbstract
Extraordinary Items
73
ExtraordinaryIncome
Extraordinary Income (434)
74
ExtraordinaryDeductions
(Less) Extraordinary Deductions (435)
75
NetExtraordinaryItems
Net Extraordinary Items (Total of line 73 less line 74)
76
IncomeTaxesExtraordinaryItems
Income Taxes-Federal and Other (409.3)
262
77
ExtraordinaryItemsAfterTaxes
Extraordinary Items After Taxes (line 75 less line 76)
78
NetIncomeLoss
Net Income (Total of line 71 and 77)
(e)
819,252,902
824,492,862


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: OperatingRevenues
Total Operating Revenues excludes amounts associated with interdepartmental transfers.
(b) Concept: OperationExpense
Total Operating Revenues excludes amounts associated with interdepartmental transfers.
(c) Concept: AllowanceForOtherFundsUsedDuringConstruction
Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net
under-collections excluded from the calculation of AFUDC rate, amount to $277.0 million. There was no short-term debt included in the calculation of the AFUDC in 2021.

During the year, the average amount of short-term debt directly related to the use of the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate, amount to $6.6 million.
(d) Concept: AllowanceForBorrowedFundsUsedDuringConstructionCredit
Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net
under-collections excluded from the calculation of AFUDC rate, amount to $277.0 million. There was no short-term debt included in the calculation of the AFUDC in 2021.
During the year, the average amount of short-term debt directly related to the use of the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate, amount to $6.6 million.
(e) Concept: NetIncomeLoss
South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.
(f) Concept: OperatingRevenues
Total Operating Revenues excludes amounts associated with interdepartmental transfers.
(g) Concept: OperationExpense
Total Operating Revenues excludes amounts associated with interdepartmental transfers.
(h) Concept: AllowanceForOtherFundsUsedDuringConstruction
Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net under-collections excluded from the calculation of AFUDC rate, amount to $166.0 million. There was no short-term debt included in the calculation of the AFUDC in 2020.

During the year, the use of the waiver for the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate did not cause any benefit.
(i) Concept: AllowanceForBorrowedFundsUsedDuringConstructionCredit
Modification of the Allowance for Funds Used During Construction Rate

San Diego Gas and Electric (SDG&E) received FERC approval to modify its existing Allowance for Funds Used During Construction (AFUDC) rate by excluding certain short-term debt associated with the financing of the net revenue under-collections recorded in its regulatory balancing and memo accounts.

Due to COVID, SDG&E also received FERC approval to modify the AFUDC rate by allowing the use of a simple average of historical short-term debt balances for the year ended 2019, instead of current period short-term debt balances. This is effective until March 31, 2022.

During the year, the average amount of short-term debt directly related to its balancing and memo accounts net under-collections excluded from the calculation of AFUDC rate, amount to $166.0 million. There was no short-term debt included in the calculation of the AFUDC in 2020.

During the year, the use of the waiver for the simple average of historical short-term debt balances excluded from the calculation of AFUDC rate did not cause any benefit.
(j) Concept: OperatingRevenues
Eliminates interdepartmental transfers $ (4,296,617)
Citizens Energy Corporation Sunrise Powerlink Lease Recoveries 10,160,424 
$ 5,863,806 
(k) Concept: OperationExpense
Eliminates interdepartmental transfers $ (4,296,617)
Citizens Energy Corporation Operating Expenses 2,003,037 
$ (2,293,581)
(l) Concept: DepreciationExpense
Depreciation expenses related to the Citizens Energy Corporation lease $ 2,836,960 
Other 1,754,599 
$ 4,591,560 
(m) Concept: TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Citizens Energy Corporation Property Tax $ 1,106,661 
Citizens Energy Corporation Payroll Tax 30,347 
$ 1,137,009 
(n) Concept: OperatingRevenues
Eliminates interdepartmental transfers $ (4,953,159)
Citizens Energy Corporation Sunrise Powerlink Lease Recoveries 8,183,923 
$ 3,230,765 
(o) Concept: OperationExpense
Eliminates interdepartmental transfers $ (4,953,158)
Citizens Energy Corporation Operating Expenses 1,573,097 
$ (3,380,063)
(p) Concept: DepreciationExpense
Depreciation expenses related to the Citizens Energy Corporation lease $ 2,836,960 
Other 1,056,459 
$ 3,893,418 
(q) Concept: TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Citizens Energy Corporation Property Tax $ 893,770 
Citizens Energy Corporation Payroll Tax 28,508 
$ 922,278 

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report


End of:
2021
/
Q4
STATEMENT OF RETAINED EARNINGS
  1. Do not report Lines 49-53 on the quarterly report.
  2. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year.
  3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b).
  4. State the purpose and amount for each reservation or appropriation of retained earnings.
  5. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order.
  6. Show dividends for each class and series of capital stock.
  7. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings.
  8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
  9. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.
Item
(a)
Contra Primary Account Affected
(b)
Current Quarter/Year Year to Date Balance
(c)
Previous Quarter/Year Year to Date Balance
(d)
UnappropriatedRetainedEarningsAbstract
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1
UnappropriatedRetainedEarnings
Balance-Beginning of Period
6,079,146,682
5,454,653,820
2
ChangesAbstract
Changes
3
AdjustmentsToRetainedEarningsAbstract
Adjustments to Retained Earnings (Account 439)
4
AdjustmentsToRetainedEarningsCreditAbstract
Adjustments to Retained Earnings Credit
9
AdjustmentsToRetainedEarningsCredit
TOTAL Credits to Retained Earnings (Acct. 439)
10
AdjustmentsToRetainedEarningsDebitAbstract
Adjustments to Retained Earnings Debit
10.1
AdjustmentsToRetainedEarningsDebit
ASU 2018-02 Stranded Tax Effects
15
AdjustmentsToRetainedEarningsDebit
TOTAL Debits to Retained Earnings (Acct. 439)
16
BalanceTransferredFromIncome
Balance Transferred from Income (Account 433 less Account 418.1)
819,252,902
824,492,862
17
AppropriationsOfRetainedEarningsAbstract
Appropriations of Retained Earnings (Acct. 436)
22
AppropriationsOfRetainedEarnings
TOTAL Appropriations of Retained Earnings (Acct. 436)
23
DividendsDeclaredPreferredStockAbstract
Dividends Declared-Preferred Stock (Account 437)
29
DividendsDeclaredPreferredStock
TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30
DividendsDeclaredCommonStockAbstract
Dividends Declared-Common Stock (Account 438)
30.1
DividendsDeclaredCommonStock
300,000,000
200,000,000
36
DividendsDeclaredCommonStock
TOTAL Dividends Declared-Common Stock (Acct. 438)
300,000,000
200,000,000
37
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38
UnappropriatedRetainedEarnings
Balance - End of Period (Total 1,9,15,16,22,29,36,37)
6,598,399,584
6,079,146,682
39
AppropriatedRetainedEarningsAbstract
APPROPRIATED RETAINED EARNINGS (Account 215)
45
AppropriatedRetainedEarnings
TOTAL Appropriated Retained Earnings (Account 215)
AppropriatedRetainedEarningsAmortizationReserveFederalAbstract
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46
AppropriatedRetainedEarningsAmortizationReserveFederal
TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47
AppropriatedRetainedEarningsIncludingReserveAmortization
TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48
RetainedEarnings
TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
6,598,399,584
6,079,146,682
UnappropriatedUndistributedSubsidiaryEarningsAbstract
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49
UnappropriatedUndistributedSubsidiaryEarnings
Balance-Beginning of Year (Debit or Credit)
50
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
51
DividendsReceived
(Less) Dividends Received (Debit)
52
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year (Total lines 49 thru 52)


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
STATEMENT OF CASH FLOWS
  1. Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc.
  2. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
  3. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
  4. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.
Description (See Instructions No.1 for explanation of codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date Quarter/Year
(c)
1
NetCashFlowFromOperatingActivitiesAbstract
Net Cash Flow from Operating Activities
2
NetIncomeLoss
Net Income (Line 78(c) on page 117)
(a)
819,252,902
824,492,862
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
755,566,306
685,671,419
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of Unrecovered Plant and Regulatory Study Costs
109,672,596
93,940,337
5.2
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Impairment - Disallowed Costs from 2019 GRC FD
1,709,067
1,058,143
8
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
153,408,253
36,783,811
9
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustment (Net)
271,798
1,050,480
10
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
101,036,636
199,928,414
11
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
19,412,441
9,945,205
12
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
33,742,383
2,970,245
13
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
39,878,578
9,766,905
14
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
166,144,447
93,977,578
15
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
103,448,946
83,037,378
16
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
81,462,879
79,095,805
17
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
18
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other (provide details in footnote):
18.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other: Net (Increase) Decrease in Prepayments and Other
39,594,171
94,119,506
18.2
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Net Increase (Decrease) in Accrued Interest and Taxes
10,234,730
21,778,194
18.3
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Wildfire Fund
18.4
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other - Net
18,676,328
21,910,750
22
NetCashFlowFromOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)
1,342,815,599
1,319,516,822
24
CashFlowsFromInvestmentActivitiesAbstract
Cash Flows from Investment Activities:
25
ConstructionAndAcquisitionOfPlantIncludingLandAbstract
Construction and Acquisition of Plant (including land):
26
GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Gross Additions to Utility Plant (less nuclear fuel)
2,301,019,620
2,020,997,426
27
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
28
GrossAdditionsToCommonUtilityPlantInvestingActivities
Gross Additions to Common Utility Plant
29
GrossAdditionsToNonutilityPlantInvestingActivities
Gross Additions to Nonutility Plant
30
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
(Less) Allowance for Other Funds Used During Construction
81,462,879
79,095,805
31
OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Other (provide details in footnote):
31.1
OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription
Other (provide details in footnote):
34
CashOutflowsForPlant
Cash Outflows for Plant (Total of lines 26 thru 33)
2,219,556,741
1,941,901,621
36
AcquisitionOfOtherNoncurrentAssets
Acquisition of Other Noncurrent Assets (d)
37
ProceedsFromDisposalOfNoncurrentAssets
Proceeds from Disposal of Noncurrent Assets (d)
39
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Investments in and Advances to Assoc. and Subsidiary Companies
28,790
40
ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies
Contributions and Advances from Assoc. and Subsidiary Companies
41
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract
Disposition of Investments in (and Advances to)
42
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44
PurchaseOfInvestmentSecurities
Purchase of Investment Securities (a)
45
ProceedsFromSalesOfInvestmentSecurities
Proceeds from Sales of Investment Securities (a)
46
LoansMadeOrPurchased
Loans Made or Purchased
47
CollectionsOnLoans
Collections on Loans
49
NetIncreaseDecreaseInReceivablesInvestingActivities
Net (Increase) Decrease in Receivables
50
NetIncreaseDecreaseInInventoryInvestingActivities
Net (Increase) Decrease in Inventory
51
NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities
Net (Increase) Decrease in Allowances Held for Speculation
52
NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
53
OtherAdjustmentsToCashFlowsFromInvestmentActivities
Other (provide details in footnote):
53.1
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
COLI - Corporate Owned Life Insurance
7,099,977
7,915,112
53.2
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Decommissioning Trust Fund Purchase
961,092,059
1,439,145,269
53.3
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Decommissioning Trust Fund Sales
961,092,059
1,439,145,269
53.4
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Increase (Decrease) in Customer Advances for Construction
5,420,024
44,858,361
57
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)
2,207,036,740
1,889,099,358
59
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
60
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
61
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Long-Term Debt (b)
745,260,000
1,398,076,000
62
ProceedsFromIssuanceOfPreferredStockFinancingActivities
Preferred Stock
63
ProceedsFromIssuanceOfCommonStockFinancingActivities
Common Stock
64
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other (provide details in footnote):
64.1
OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription
Other: LTD Issuance Cost
7,762,644
10,654,000
64.2
OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription
Other: Equity Contribution from Sempra Energy
66
NetIncreaseInShortTermDebt
Net Increase in Short-Term Debt (c)
775,767,324
200,000,000
67
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (provide details in footnote):
67.1
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (provide details in footnote):
70
CashProvidedByOutsideSources
Cash Provided by Outside Sources (Total 61 thru 69)
1,513,264,680
1,587,422,000
72
PaymentsForRetirementAbstract
Payments for Retirement of:
73
PaymentsForRetirementOfLongTermDebtFinancingActivities
Long-term Debt (b)
385,714,000
486,979,000
74
PaymentsForRetirementOfPreferredStockFinancingActivities
Preferred Stock
75
PaymentsForRetirementOfCommonStockFinancingActivities
Common Stock
76
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other (provide details in footnote):
76.1
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Other (provide details in footnote):
76.2
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Short-Term Debt (Term Loan)
200,000,000
78
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
79,768,524
80
DividendsOnPreferredStock
Dividends on Preferred Stock
81
DividendsOnCommonStock
Dividends on Common Stock
300,000,000
200,000,000
83
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)
627,550,680
820,674,476
85
NetIncreaseDecreaseInCashAndCashEquivalentsAbstract
Net Increase (Decrease) in Cash and Cash Equivalents
86
NetIncreaseDecreaseInCashAndCashEquivalents
Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)
236,670,461
251,091,940
88
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
261,589,840
10,497,900
90
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period
24,919,379
261,589,840


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: NetIncomeLoss
South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
NOTES TO FINANCIAL STATEMENTS
  1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
  2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
  3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
  4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
  5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
  6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
  7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
  8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
  9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.
Notes for Statement of Cash Flows:
Supplemental Disclosure of Cash Flow Information:12/31/2021
Income tax payments, net of $66,791,792 
Interest payments, net of amounts capitalized$402,433,408 
Reconciliation of Cash and Cash Equivalents at December 31, 2021:
Account 131Cash$24,919,380 
Account 135Working Funds— 
Account 136Temporary Cash Investments— 
$24,919,380 
Supplemental Disclosure of Non-Cash Investing & Financing Activities:
Increase in finance lease (PPA & Fleet and Other Equipment) obligations for investments in PP&E$23,302,033 
Accrued Capital Expenditures$227,738,753 
Increase in ARO for investment in PP&E$13,968,906 

B.Basis of Presentation and Notes to Financial Statements
Beginning on page 123.3 are excerpts from the Sempra (or the parent) Annual Report on Form 10-K for the period ending December 31, 2021, as filed with the SEC on February 25, 2022. The following disclosures contain information in accordance with SEC requirements.
These financial statements, included on pages 110 through 122b of this report, were prepared in accordance with the accounting requirements of FERC as set forth in the applicable Uniform System of Accounts and published accounting releases. Such requirements and published accounting releases constitute a comprehensive basis of accounting other than U.S. GAAP. The principal differences of this basis of accounting from U.S. GAAP include, but are not necessarily limited to, the accounting for and classification of:
Certain deferred income taxes and regulatory assets and liabilities
Certain assets and liabilities between current and non-current
Certain cost of removal obligations, and property reserves
Classification of interest and penalties associated with income taxes
Electricity sales for resale and purchase power expenses
Certain revenues net of related costs
Capital lease treatment of certain contracts
Certain plant in service, accumulated depreciation, and regulatory assets
Certain pension costs between other income and A&G
Certain balance sheet treatment for operating lease for U.S. GAAP purposes are reported under Property Under Capital Leases, Amortization and Capital Lease Obligations.
Certain lease expenses between depreciation, interest expenses, and other line items.
Software costs relating to cloud computing between prepaid expenses and utility plant
Due to the differences between FERC and U.S. GAAP reporting requirements as mentioned above, certain amounts disclosed in Notes 1-13 may not agree to balances in the FERC financial statements.
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

BASIS OF PRESENTATION
This is a report of SDG&E. SDG&E’s common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra Energy. References in this report to “we,” and “our” are to SDG&E, unless otherwise indicated by the context.

Use of Estimates in the Preparation of the Financial Statements
We have prepared our Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.
REGULATED OPERATIONS
SDG&E’s accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, SDG&E records regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.
Determining probability of recovery of regulatory assets requires significant judgment by management and may include, but is not limited to, consideration of:
the nature of the event giving rise to the assessment
existing statutes and regulatory code
legal precedents
regulatory principles and analogous regulatory actions
testimony presented in regulatory hearings
regulatory orders
a commission-authorized mechanism established for the accumulation of costs
status of applications for rehearings or state court appeals
specific approval from a commission
historical experience

FAIR VALUE MEASUREMENTS
We measure certain assets and liabilities at fair value on a recurring basis, primarily NDT and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances.
A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.
We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 – Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, short-term investments, and U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:
quoted forward prices for commodities
time value
current market and contractual prices for the underlying instruments
volatility factors
other relevant economic measures
Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as over-the-counter forwards and options.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions.

CASH AND CASH EQUIVALENTS

CREDIT LOSSES
We are exposed to credit losses from financial assets measured at amortized cost, including trade and other accounts receivable.
We regularly monitor and evaluate credit losses and record allowances for expected credit losses, if necessary, for trade and other accounts receivable using a combination of factors, including past-due status based on contractual terms, trends in write-offs, the age of the receivables and customer payment patterns, historical and industry trends, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies, pandemics and other factors. We write off financial assets measured at amortized cost in the period in which we determine they are not recoverable. We record recoveries of amounts previously written off when it is known that they will be recovered.
In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers, waiving late payment fees, and offering flexible payment plans. At the CPUC’s direction, SDG&E is automatically enrolling residential and small business customers with past-due balances in long-term repayment plans.
As we discuss in Note 4, the CPUC authorized SDG&E to track and request recovery of incremental costs, including uncollectible expenses, associated with complying with customer protection measures ordered by the CPUC related to the COVID-19 pandemic.
In connection with a separate CPUC decision addressing residential service disconnections, SDG&E established a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding utility bill amounts provided under the AMP, as we discuss in Note 4.
In 2021, SDG&E applied, on behalf of its customers, for financial assistance from the California Department of Community Services and Development under the California Arrearage Payment Program, which provided funds of $63 million. In the first quarter of 2022, SDG&E received and applied the amounts directly to eligible customer accounts to reduce past due balances.
We provide below allowances and changes in allowances for credit losses for trade receivables and other receivables. We record changes in the allowances for credit losses related to Accounts Receivable – Trade in regulatory accounts.
RECEIVABLES – ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
Years ended December 31,
202120202019
Allowances for credit losses at January 1$69 $14 $11 
Provisions for expected credit losses23 65 10 
Write-offs(26)(10)(7)
Allowances for credit losses at December 31$66 $69 $14 
Allowances for credit losses are included in the Balance Sheet as follows:
ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
Years ended December 31,
202120202019
Accounts receivable – trade, net$42 $55 $
Accounts receivable – other, net22 14 10 
Other long-term assets— — 
Total allowances for credit losses$66 $69 $14 

CONCENTRATION OF CREDIT RISK
Credit risk is the risk of loss that would be incurred as a result of nonperformance by our counterparties on their contractual obligations. We have policies governing the management of credit risk that are administered by our credit department and overseen by our risk management committee.
This oversight includes calculating current and potential credit risk on a regular basis and monitoring actual balances in comparison to approved limits. We establish credit limits based on risk and return considerations under terms customarily available in the industry. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of:
prospective counterparties’ financial condition (including credit ratings)
collateral requirements
the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty
downgrade triggers
We believe that we have provided adequate reserves for counterparty nonperformance in our allowances for credit losses

INVENTORIES
We value natural gas inventory using the last-in first-out method. As inventories are sold, differences between the last-in first-out valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. We generally value materials and supplies at the lower of average cost or net realizable value.
The components of inventories are as follows:
INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
SDG&E
20212020
Natural gas$— $— 
Materials and supplies123 104 
Total$123 $104 

WILDFIRE FUND
In July 2019, the Wildfire Legislation was signed into law. The Wildfire Legislation addresses certain issues related to catastrophic wildfires in the State of California and their impact on electric IOUs. The issues addressed include wildfire mitigation, cost recovery standards and requirements, a wildfire fund, a cap on liability, and the establishment of a wildfire safety board.
The Wildfire Legislation provided that SDG&E would not recover the ROE on its first $215 million of fire risk mitigation capital expenditures.
The Wildfire Legislation established a revised legal standard for the recovery of wildfire costs (Revised Prudent Manager Standard) and established a fund (the Wildfire Fund) designed to provide liquidity to SDG&E, PG&E and Edison to pay IOU wildfire-related claims in the event that the governmental agency responsible for determining causation determines the applicable IOU’s equipment caused the ignition of a wildfire, primary insurance coverage is exceeded and certain other conditions are satisfied. A primary purpose of the Wildfire Fund is to pool resources provided by shareholders and ratepayers of the IOUs and make those resources available to reimburse the IOUs for third-party wildfire claims incurred after July 12, 2019, the effective date of the Wildfire Legislation, subject to certain limitations.
An IOU may seek payment from the Wildfire Fund for settled or adjudicated third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1 billion or the IOU’s required amount of insurance coverage as recommended by the Wildfire Fund’s administrator. Wildfire claims approved by the Wildfire Fund’s administrator will be paid by the Wildfire Fund to the IOU to the extent funds are available. These utilized funds will be subject to review by the CPUC, which will make a determination as to the degree an IOU’s conduct related to an ignition of a wildfire was prudent or imprudent. The Revised Prudent Manager Standard requires that the CPUC apply clear standards when reviewing wildfire liability losses paid when determining the reasonableness of an IOU’s conduct related to an ignition. Under this standard, the conduct under review related to the ignition may include factors within and beyond the IOU’s control, including humidity, temperature and winds. Costs and expenses may be allocated for cost recovery in full or in part. Also, under this standard, an IOU’s conduct will be deemed reasonable if a valid annual safety certification is in place at the time of the ignition, unless a serious doubt is raised, in which case the burden shifts to the utility to dispel that doubt. The IOUs will receive an annual safety certification from the CPUC if they meet various requirements.
If an IOU has maintained a valid annual safety certification, to the extent it is found to be imprudent, claims will be reimbursable by the IOU to the Wildfire Fund up to a cap based on the IOU’s rate base. The aggregate requirement to reimburse the Wildfire Fund over a trailing three calendar year period is capped at 20% of the equity portion of an IOU’s electric transmission and distribution rate base in the year of the prudency determination. Based on its 2021 rate base, the liability cap for SDG&E is approximately $1.1 billion, which is adjusted annually. The liability cap will apply on a rolling three-year basis so long as future annual safety certifications are received and the Wildfire Fund has not been terminated, which could occur if funds are exhausted. Amounts in excess of the liability cap and amounts that are determined to be prudently incurred do not need to be reimbursed by an IOU to the Wildfire Fund. The Wildfire Fund does not have a specified term and coverage will continue until the assets of the Wildfire Fund are exhausted and the Wildfire Fund is terminated, in which case, the remaining funds, if any, will be transferred to California’s general fund to be used for fire risk mitigation programs.
In July 2021, the CPUC approved SDG&E’s 2021 Wildfire Mitigation Plan. In July 2021, the CPUC’s Wildfire Safety Division became the OEIS under the California Natural Resources Agency. As successor to the Wildfire Safety Division, the
OEIS maintains the duties and responsibilities of the former Wildfire Safety Division with respect to Wildfire Mitigation Plans. The 2021 Wildfire Mitigation Plan is effective until the OEIS approves a new plan. In December 2021, SDG&E received its 2021 wildfire safety certification from the OEIS, which is valid for 12 months from the issue date.
The Wildfire Fund was initially funded up to $10.5 billion by a loan from the State of California Surplus Money Investment Fund. The loan is financed through a DWR bond, which was put in place on October 1, 2020 and is securitized through a dedicated surcharge on ratepayers’ bills attributable to the DWR. In October 2019, the CPUC adopted a decision authorizing a non-bypassable charge to be collected by the IOUs to support the anticipated DWR bond issuance authorized by AB 1054. The CPUC decision also determined that ratepayers of non-participating electrical corporations shall not pay the non-bypassable charge.
The Wildfire Fund was also funded by initial shareholder contributions from the IOUs totaling $7.5 billion. SDG&E’s share was $322.5 million. The IOUs are also required to make annual shareholder contributions to the Wildfire Fund with an aggregate value of $3 billion over a 10-year period starting in 2019. SDG&E’s share is $129 million. The contributions are not subject to rate recovery.
In a complaint filed in U.S. District Court for the Northern District of California in July 2019, plaintiffs seek to invalidate AB 1054 based on allegations that the legislation violates federal law. The district court and, subsequently, the U.S. Court of Appeals for the Ninth Circuit dismissed the complaint.
Wildfire Fund Asset and Obligation
In 2019, SDG&E recorded both a Wildfire Fund asset and a related obligation for its commitment to make shareholder contributions of $451.5 million to the Wildfire Fund, measured at present value as of July 25, 2019 (the date by which both Edison and SDG&E opted to contribute to the Wildfire Fund). SDG&E paid its initial shareholder contribution of $322.5 million to the Wildfire Fund in September 2019. SDG&E funded this contribution with proceeds from an equity contribution from Sempra. SDG&E expects to continue to make annual shareholder contributions of $12.9 million through December 31, 2028. SDG&E accretes the present value of the Wildfire Fund obligation until the liability is settled.
SDG&E is amortizing the Wildfire Fund asset on a straight-line basis over the estimated period of benefit, as adjusted for utilization by the IOUs. The estimated period of benefit of the Wildfire Fund asset is 15 years and is based on several assumptions, including, but not limited to:
historical wildfire experience of each IOU in the State of California, including frequency and severity of the wildfires
the value of property potentially damaged by wildfires
the effectiveness of wildfire risk mitigation efforts by each IOU
liability cap of each IOU
IOU prudency determination levels
FERC jurisdictional allocation levels
insurance coverage levels
The use of different assumptions, or changes to the assumptions used, could have a significant impact on the estimated period of benefit of the Wildfire Fund asset. We periodically evaluate the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in these assumptions. SDG&E recognizes a reduction of its Wildfire Fund asset and records a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, decrease the Wildfire Fund asset and remaining available coverage.
The following table summarizes the location of balances related to the Wildfire Fund on SDG&E’s Balance Sheet and Statement of Operations.
WILDFIRE FUND
(Dollars in millions)
December 31,
Location20212020
Wildfire Fund asset:
CurrentPrepaid Expenses$29 $29 
NoncurrentWildfire Fund331 363 
Wildfire Fund obligation:
CurrentOther Current Liabilities$13 $13 
NoncurrentDeferred Credits and Other64 75 
Years ended December 31,
20212020
Amortization of Wildfire Fund assetOperation and Maintenance$29 $29 
Impairment of Wildfire Fund assetOperation and Maintenance — 
Accretion of Wildfire Fund obligationOperation and Maintenance

INCOME TAXES
Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. Investment tax credits from prior years are amortized to income over the estimated service lives of the properties as required by the CPUC.
Under the regulatory accounting treatment required for flow-through temporary differences, we recognize:
regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and
regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned to customers.
When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.
Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.
We provide additional information about income taxes in Note 6.

GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS
SDG&E is required by AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. Many GHG allowances are allocated to us on behalf of our customers at no cost. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. We balance costs and revenues associated with the GHG program through regulatory balancing accounts. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.
RENEWABLE ENERGY CERTIFICATES
RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.
Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS Program established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS Program. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Statement of Operations.

PROPERTY, PLANT AND EQUIPMENT
PP&E is recorded at cost and primarily represents the buildings, equipment and other facilities used to provide natural gas and electric utility services, including construction work in progress. . Our plant costs include labor, materials and contract services and expenditures for replacement parts incurred during a major maintenance outage of a plant. In addition, the cost of utility plant includes AFUDC. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation.

We discuss assets collateralized as security for certain indebtedness in Note 5.
PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(Dollars in millions)
December 31,
Depreciation rates for years ended
December 31,
20212020202120202019
Natural gas operations
$3,200 $2,805 2.55 %2.51 %2.47 %
Electric distribution
9,471 8,592 3.93 3.90 3.94 
Electric transmission(1)
7,577 7,156 3.02 3.10 2.79 
Electric generation
2,446 2,440 4.74 4.56 4.50 
Other electric2,100 1,743 7.23 6.92 6.61 
Construction work in progress(1)
1,662 1,700 N/AN/AN/A
Total
$26,456 $24,436 
(1)At At December 31, 2021, includes $542 in electric transmission assets and $5 in construction work in progress related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in the Statement of Operations.

Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period, or the remaining term of the site leases, whichever is shortest.
DEPRECIATION EXPENSE
(Dollars in millions)
Years ended December 31,
202120202019
SDG&E
$865 $779 $719 
ACCUMULATED DEPRECIATION
(Dollars in millions)
December 31,
20212020
Accumulated depreciation:
Natural gas operations$919 $870 
Electric transmission, distribution and generation(1)
5,489 5,145 
Total
6,408 6,015 
(1)Includes $292 at December 31, 2021 related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.

We finance our construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. We earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from customers over the expected useful lives of the assets.
We capitalize interest costs incurred to finance capital projects that have not commenced planned principal operations.
The table below summarizes capitalized financing costs, comprised of AFUDC and capitalized interest.
CAPITALIZED FINANCING COSTS
(Dollars in millions)
Years ended December 31,
202120202019
$106 $104 $75 
We provide additional information about temporary adjustments to the AFUDC rate calculation in relation to the COVID-19 pandemic in Note 4.

LONG-LIVED ASSETS
We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated entities. A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

ASSET RETIREMENT OBLIGATIONS
For tangible long-lived assets, we record AROs for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record the estimated retirement cost using the present value of the obligation at the time the asset is placed into service, and recognize that cost over the life of the related asset by depreciating the asset retirement cost and accreting the obligation until the liability is settled. We record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.
We have recorded AROs related to various assets, including:
fuel and storage tanks
natural gas transmission and distribution systems
hazardous waste storage facilities
asbestos-containing construction materials
nuclear power facilities
electric transmission and distribution systems
energy storage systems
power generation plants
The changes in ARO are as follows:
CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
20212020
Balance as of January 1
$876 $866 
Accretion expense38 39 
Liabilities incurred and acquired— 
Payments(60)(60)
Revisions(1)
34 31 
Balance at December 31$890 $876 
(1)SDG&E’s increase in ARO in 2021 includes $22 million due to a revised estimate related to the decommissioning of SONGS, which is offset in noncurrent Regulatory Assets.

CONTINGENCIES
We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and if:
information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and
the amount of the loss or a range of possible losses can be reasonably estimated.
We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.

LEGAL FEES
Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.

COMPREHENSIVE INCOME
Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:
certain hedging activities
changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans
The Statement of Comprehensive Income (Loss) show the changes in the components of OCI. The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
(Dollars in millions)
Pension
and other
postretirement
benefits
Total accumulated other
comprehensive income (loss)
Balance as of December 31, 2018
$(10)$(10)
Adoption of ASU 2018-02$(2)$(2)
OCI before reclassifications(5)(5)
Amounts reclassified from AOCI
Net OCI(6)(6)
Balance as of December 31, 2019(16)(16)
OCI before reclassifications(2)
(4)(4)
Amounts reclassified from AOCI(2)
10 10 
Net OCI
Balance as of December 31, 2020(10)(10)
OCI before reclassifications(1)(1)
Amounts reclassified from AOCI
Net OCI— — 
Balance as of December 31, 2021
$(10)$(10)
(1)All amounts are net of income tax, if subject to tax.
(2)Pension and Other Postretirement Benefits and Total AOCI include $6 in transfers of liabilities from SDG&E to SoCalGas and $3 in transfers of liabilities from SDG&E to Sempra in 2020 related to the nonqualified pension plans.

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated
other comprehensive income (loss) components
Amounts reclassified from accumulated
other comprehensive income (loss)
Affected line item on
Statement of Operations
Years ended December 31,
202120202019
Pension and other postretirement benefits(1):
Amortization of actuarial loss
$— $$— 
Other Income, Net
Settlement charges
Other Income, Net
Total before income tax
— (1)— 
Income Tax Expense
Net of income tax
$$$
Total reclassifications for the period, net of tax
$$$
(1)Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 7).
REVENUES
See Note 3 for a description of significant accounting policies for revenues.

OPERATION AND MAINTENANCE EXPENSES
Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, insurance, rent and litigation expense.

TRANSACTIONS WITH AFFILIATES
We summarize amounts due from and to unconsolidated affiliates in the following table.

AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
December 31,
20212020
Sempra Energy
$(40)$(38)
SoCalGas
(48)(21)
Various affiliates
(9)(5)
Total due to unconsolidated affiliates – current
$(97)$(64)
Income taxes due from Sempra Energy(1)
$19 $— 
(1)SDG&E is included in the consolidated income tax return of Sempra, and its income tax expense is computed as an amount equal to that which would result from having always filed a separate return..

The following table summarizes revenues and cost of sales from unconsolidated affiliates.
REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
Years ended December 31,
202120202019
Revenues
$11 $$
Cost of Sales
$103 $79 $74 

Sempra, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E may make short-term advances of surplus cash to Sempra at interest rates based on the federal funds effective rate plus a margin of 13 to 20 bps, depending on the loan balance.
SoCalGas provides natural gas transportation and storage services for SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales.
SDG&E and SoCalGas charge one another, as well as other Sempra affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to O&M.
The natural gas supply for SDG&E’s core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service; therefore, revenues and costs related to SDG&E are presented net in SoCalGas’ Statements of Operations.
SDG&E has a 20-year contract for up to 155 MW of renewable power supplied from the ESJ wind power generation facility. A second 20-year contract between SDG&E and ESJ for up to 108 MW of renewable power supplied from the same facility commenced in January 2022.

RESTRICTED NET ASSETS
The CPUC’s regulation of SDG&E’s capital structures limits the amounts available for dividends and loans to Sempra. At December 31, 2021, Sempra could have received combined loans and dividends of approximately $798 million from SDG&E.
The payment and amount of future dividends are at the discretion of SDG&E’s boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra from SDG&E:
The CPUC requires that SDG&E’s common equity ratio be no lower than one percentage point below the CPUC-authorized percentage of its authorized capital structure. The authorized percentage at December 31, 2021 is 52%.
SDG&E has a revolving credit line that requires it to maintain a ratio of indebtedness to capitalization (as defined in the agreement) of no more than 65%, as we discuss in Note 5.
Based on these restrictions, at December 31, 2021, SDG&E’s restricted net assets were $7.5 billion which could not be transferred to Sempra.

OTHER INCOME, NET
Other Income, Net on the Statement of Operations consists of the following:
OTHER INCOME, NET
(Dollars in millions)
Years ended December 31,
202120202019
Allowance for equity funds used during construction
$81 $79 $56 
Non-service component of net periodic benefit (cost) credit
(13)(20)(20)
Interest on regulatory balancing accounts, net
13 
Sundry, net
(10)(16)(10)
Total
$64 $52 $39 
NOTE 2. NEW ACCOUNTING STANDARDS
No recent accounting pronouncements have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures.
NOTE 3. REVENUES
The following table disaggregates our revenues from contracts with customers by major service line and market. The majority of our revenue is recognized over time.
DISAGGREGATED REVENUES
(Dollars in millions)
Year ended December 31, 2021
By major service line:
Utilities
$5,144 
Energy-related businesses
— 
Revenues from contracts with customers
$5,144 
By market:
Gas
$790 
Electric
4,354 
Revenues from contracts with customers
$5,144 
Revenues from contracts with customers
$5,144 
Utilities regulatory revenues
360 
Other revenues
— 
Total revenues
$5,504 
Year ended December 31, 2020
By major service line:
Utilities
$4,920 
Energy-related businesses
— 
Revenues from contracts with customers
$4,920 
By market:
Gas
$692 
Electric
4,228 
Revenues from contracts with customers
$4,920 
Revenues from contracts with customers
$4,920 
Utilities regulatory revenues
393 
Other revenues
— 
Total revenues
$5,313 
Year ended December 31, 2019
By major service line:
Utilities
$4,820 
Energy-related businesses
— 
Revenues from contracts with customers
$4,820 
By market:
Gas
$587 
Electric4,233 
Revenues from contracts with customers$4,820 
Revenues from contracts with customers$4,820 
Utilities regulatory revenues106 
Other revenues— 
Total revenues$4,926 
REVENUES FROM CONTRACTS WITH CUSTOMERS
Our revenues from contracts with customers are primarily related to the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity. We assess our revenues on a contract-by-contract basis as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.
We generally recognize revenues when performance of the promised commodity service is provided to our customers and we invoice our customers for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of natural gas and electricity and providing of natural gas storage services as ongoing and integrated services. Generally, natural gas or electricity services are received and consumed by the customer simultaneously. Our performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of our performance obligations can be directly measured by the amount of natural gas or electricity delivered to the customer. In most cases, the right to consideration from the customer directly corresponds to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice.
The payment terms in our customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.
We exclude sales and usage-based taxes from revenues. In addition, we pay franchise fees to operate in various municipalities and bill these franchise fees to our customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of our ability to collect from the customer, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.

Utilities Revenues
Utilities revenues include the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity.
Utilities revenues are derived from and recognized upon the delivery of natural gas or electricity services to customers. Amounts that we bill our customers are based on tariffs set by regulators within the respective state or country. For SDG&E, which follows the provisions of U.S. GAAP governing rate-regulated operations as we discuss in Note 1, amounts that it bills to customers also include adjustments for previously recognized regulatory revenues.
We recognize revenues based on regulator-approved revenue requirements, which allow us to recover reasonable operating costs and provides the opportunity to realize our authorized rates of return on our investments. While our revenues are not affected by actual sales volumes, the pattern of our revenue recognition during the year is affected by seasonality. We recognize annual authorized revenue for customers using seasonal factors established in applicable proceedings, which generally results in a significant portion of operating revenues being recognized in the third quarter of each year.
We have an arrangement to provide the California ISO with the ability to control its high-voltage transmission lines for prices approved by the FERC. Revenue is recognized over time as access is provided to the California ISO.
Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings, which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.
We recognize revenues from the sale of allocated California GHG emissions allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and we have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. We balance costs and revenues associated with the GHG program through regulatory balancing accounts.
Remaining Performance Obligations
We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) variable consideration recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.
For contracts greater than one year, at December 31, 2021, we expect to recognize revenue related to the fixed fee component of the consideration as shown below.

REMAINING PERFORMANCE OBLIGATIONS(1)
(Dollars in millions)
2022$
2023
2024
2025
2026
Thereafter
63 
Total revenues to be recognized
$83 
(1)Excludes intercompany transactions.

Contract Balances from Revenues from Contracts with Customers
From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.
Activities within our contract liabilities are presented below.
CONTRACT LIABILITIES
(Dollars in millions)
202120202019
Opening balance, January 1
$(87)$(91)$— 
Revenue from performance obligations satisfied during reporting period
Payments received in advance
— — (92)
Balance at December 31(1)
$(83)$(87)$(91)
(1)Balances at December 31, 2021, 2020 and 2019 include $4, $4 and $4, respectively, in Other Current Liabilities and $79, $83 and $87, respectively, in Deferred Credits and Other.

Receivables from Revenues from Contracts with Customers
The table below shows receivable balances associated with revenues from contracts with customers on our Balance Sheet.
RECEIVABLES FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(Dollars in millions)
December 31,
20212020
Accounts receivable – trade, net
$715 $573 
Accounts receivable – other, net
Due from unconsolidated affiliates – current(1)
Other long-term assets25 — 
Total
$751 $583 
(1)Amount is presented net of amounts due to unconsolidated affiliates on the Balance Sheet, when right of offset exists.
In connection with the COVID-19 pandemic and at the direction of the CPUC, we implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers, waiving late payment fees, and offering flexible payment plans. At the CPUC’s direction, we are automatically enrolling residential and small business customers with past-due balances in long-term repayment plans.
In 2021, we applied, on behalf of our customers, for financial assistance from the California Department of Community Services and Development under the California Arrearage Payment Program, which provided funds of $63 million. In the first quarter of 2022, we received and applied the amounts directly to eligible customer accounts to reduce past due balances.

REVENUES FROM SOURCES OTHER THAN CONTRACTS WITH CUSTOMERS
Certain of our revenues are derived from sources other than contracts with customers and are accounted for under other accounting standards outside the scope of ASC 606.

Utilities Regulatory Revenues
Alternative Revenue Programs
We recognize revenues from alternative revenue programs when the regulator-specified conditions for recognition have been met and adjust these revenues as they are recovered or refunded through future utility service.
Decoupled revenues. As discussed earlier, the regulatory framework requires SDG&E to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for natural gas and electricity will generally vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for SDG&E to use a “decoupling” mechanism, which allows it to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.
Incentive mechanisms. The CPUC applies performance-based measures and incentive mechanisms to all California IOUs, under which SDG&E has earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.
Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.
Other Cost-Based Regulatory Recovery
The CPUC and the FERC authorize SDG&E to collect revenue requirements for operating costs and capital related costs (such as depreciation, taxes and return on rate base) from customers, including:
costs to purchase natural gas and electricity;
costs associated with administering public purpose, demand response, and customer energy efficiency programs;
other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and
costs associated with third party liability insurance premiums.
Authorized costs are recovered as the commodity service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded within a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met at the time the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund for programs authorized, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers.
We discuss balancing accounts and their effects further in Note 4.
NOTE 4. REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES
We show the details of regulatory assets and liabilities in the following table and discuss them below. With the exception of regulatory balancing accounts, we generally do not earn a return on our regulatory assets until such time as a related cash expenditure has been made. Upon the occurrence of a cash expenditure associated with a regulatory asset, the related amounts are recoverable through a regulatory account mechanism for which we earn a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate. The periods during which we recognize a regulatory asset while we do not earn a return vary by regulatory asset.

REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
December 31,
20212020
Fixed-price contracts and other derivatives$(50)$(53)
Deferred income taxes recoverable (refundable) in rates125 22 
Pension and other postretirement benefit plan obligations(7)50 
Removal obligations(2,251)(2,121)
Environmental costs62 56 
Sunrise Powerlink fire mitigation122 121 
Regulatory balancing accounts(1)(2)
Commodity – electric77 72 
Gas transportation49 35 
Safety and reliability67 67 
Public purpose programs(107)(158)
2019 GRC retroactive impacts— 56 
Wildfire mitigation plan178 93 
Liability insurance premium110 79 
Other balancing accounts207 61 
Other regulatory assets (liabilities), net(2)
119 72 
Total
$(1,299)$(1,548)
(1)At December 31, 2021 and 2020, the noncurrent portion of regulatory balancing accounts – net undercollected was $358 million and $139 million, respectively.
(2)Includes regulatory assets earning a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate.


Regulatory Assets Not Earning a Return
Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased
based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. The related amounts are recovered in rates once these contracts are settled, generally within two years.
Deferred income taxes recoverable/refundable in rates are based on current regulatory ratemaking and income tax laws. SDG&E expects to recover/refund net regulatory assets/liabilities related to deferred income taxes over the lives of the assets, ranging from 5 to 69 years, that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities include excess deferred income taxes resulting from statutory income tax rate changes and certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 6.
Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets. The assets are recovered in rates as the plans are funded.
The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.
Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).
Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.
The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 48-year period.

Regulatory Assets Earning a Return
Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized amounts. Depreciation, taxes and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. The adopted revenue requirements in the 2019 GRC FD associated with the period from January 1, 2019 through December 31, 2019 were recovered in rates over a 24-month period that began in January 2020.
Amortization expense on certain regulatory assets for the years ended December 31, 2021, 2020 and 2019 was $5 million, $4 million and $3 million, respectively.

COVID-19 Pandemic Protections
In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers, waiving late payment fees, and offering flexible payment plans. At the CPUC’s direction, SDG&E is automatically enrolling residential and small business customers with past-due balances in long-term repayment plans.
In 2021, SDG&E applied, on behalf of its customers, for financial assistance from the California Department of Community Services and Development under the California Arrearage Payment Program, which provided funds of $63 million. In the first quarter of 2022, SDG&E received and applied the amounts directly to eligible customer accounts to reduce past due balances.
SDG&E has been authorized to track and request recovery of incremental costs associated with complying with customer protection measures implemented by the CPUC related to the COVID-19 pandemic, including costs associated with suspending service disconnections and uncollectible expenses that arise from customers’ failure to pay. We expect to pursue recovery of small and medium-large commercial and industrial customers’ tracked costs in rates in future CPUC proceedings, which recovery is not assured. Uncollectible expenses related to residential customers are recorded in a two-way balancing account as we discuss below.
Disconnection OIR
In June 2020, the CPUC issued a decision to adopt certain customer protections to reduce residential customer disconnections and improve reconnection processes, including, among other things, imposing limitations on service disconnections, elimination of deposit requirements and reconnection fees, establishment of the AMP that provides successfully participating, income-qualified residential customers with relief from outstanding utility bill amounts, and increased outreach and marketing efforts. As permitted by the decision, SDG&E has established a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding utility bill amounts provided under the AMP.

CPUC GRC
The CPUC uses GRCs to set rates designed to allow SDG&E to recover reasonable operating costs and to provide the opportunity to realize authorized rates of return on its investments.
In September 2019, the CPUC issued a final decision in the 2019 GRC approving SDG&E’s test year revenues for 2019 and attrition year adjustments for 2020 and 2021, which was effective retroactively to January 1, 2019. This is the first GRC that includes revenues authorized for risk assessment mitigation phase activities.
The 2019 GRC FD approved a test year 2019 revenue requirement of $1,990 million for SDG&E’s combined operations ($1,590 million for its electric operations and $400 million for its natural gas operations).
The increases include separately authorized components for O&M and capital-related costs, as follows:
AUTHORIZED REVENUE REQUIREMENT INCREASES FOR 2020 AND 2021
(Dollars in millions)
2020 increase from 2019
2021 increase from 2020
Revenue increase
Percent increase
Revenue increase
Percent increase
O&M
$20 2.64 %$19 2.47 %
Capital-related costs
114 9.74 83 6.47 
Total increase
$134 6.74 $102 4.83 

In January 2020, the CPUC issued a final decision implementing a four-year GRC cycle for California IOUs and SDG&E was directed to file a petition for modification to revise its 2019 GRC to add two additional attrition years, resulting in a transitional five-year GRC period (2019-2023). In May 2021, the CPUC issued a final decision approving SDG&E’s request to continue its authorized post-test year mechanisms for 2022 and 2023. For SDG&E, the decision authorizes revenue requirement increases of $87 million (3.92%) for 2022 and $86 million (3.70%) for 2023.
The 2019 GRC FD approved SDG&E’s establishment of two-way liability insurance premium balancing accounts, including wildfire insurance premium costs based on a specific level of coverage. The 2019 GRC FD also permits SDG&E to seek recovery of additional liability insurance coverage.
The 2019 GRC FD clarified that differences between incurred and forecasted income tax expense due to forecasting differences are not subject to tracking in the income tax expense memorandum account beginning in 2019. SDG&E previously recorded regulatory liabilities, inclusive of interest, associated with the 2016 through 2018 tracked forecasting differences of $86 million. In April 2020, the CPUC confirmed treatment of the two-way income tax expense memorandum account for these 2016 through 2018 balances, at which time we released these regulatory liability balances to revenues and regulatory interest.

CPUC Cost of Capital
A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized return on rate base. In December 2019, the CPUC approved the cost of capital and rate structures (shown in the table below) for SDG&E that became effective on January 1, 2020 and will remain in effect through December 31, 2022, subject to the CCM.

CPUC AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE, SUBJECT TO THE CCM
Authorized weighting
Return on rate base
Weighted return on rate base
Long-Term Debt
45.25 %4.59 %2.08 %
Preferred Stock
2.75 6.22 0.17 
Common Equity
52.00 10.20 5.30 
100.00 %7.55 %

The CCM applies in the interim years between required cost of capital applications and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (the CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus 1.000% at the end of the measurement period. The index applicable to SDG&E is based on its credit rating. SDG&E’s CCM benchmark rate is 4.498% based on Moody’s Baa- utility bond index. Alternatively, under the CCM, SDG&E is permitted to file a cost of capital application in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole.
For the measurement period ended September 30, 2021, the CCM would trigger for SDG&E because the average Moody’s Baa- utility bond index between October 1, 2020 and September 30, 2021 was 1.17% below SDG&E’s CCM benchmark rate of 4.498%. In August 2021, SDG&E filed an application with the CPUC to update its cost of capital effective January 1, 2022 due to the ongoing effects of the COVID-19 pandemic rather than have the CCM apply. In this application, SDG&E proposed to adjust its authorized capital structure by increasing its common equity ratio from 52% to 54%. SDG&E also proposed to increase its authorized ROE from 10.20% to 10.55% and decrease its authorized cost of debt from 4.59% to 3.84%. As a result, SDG&E’s proposed return on rate base would decrease from 7.55% to 7.46% if such application is approved by the CPUC as filed. SDG&E filed a joint motion with PG&E and Edison to consolidate all three utilities’ cost of capital applications given the overlapping issues of law and fact, which joint motion was granted in October 2021. In December 2021, the CPUC established a proceeding to determine if SDG&E’s cost of capital was impacted by an extraordinary event. If the CPUC finds that there was not an extraordinary event, the CCM would be effective retroactive to January 1, 2022 and would automatically adjust SDG&E’s authorized ROE from 10.20% to 9.62% and adjust its authorized cost of debt to reflect the then current embedded cost and projected interest rate. If the CPUC finds that there was an extraordinary event, it will then determine whether to suspend the CCM for 2022 and preserve SDG&E’s current authorized cost of capital or hold a second phase of the proceeding to set a new cost of capital for 2022. SDG&E expects a final decision in the second half of 2022. In December 2021, the CPUC granted SDG&E the establishment of memorandum accounts effective January 1, 2022 to track any differences in revenue requirement resulting from the interim cost of capital decision expected in 2022.
SDG&E is required to file its next cost of capital application in April 2022 for a January 1, 2023 effective date.
FERC Rate Matters
SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets.
SDG&E’s TO4 ROE of 10.05% was the basis of SDG&E’s FERC-related revenue recognition until March 2020, when the FERC approved the settlement terms that SDG&E and all settling parties reached in October 2019 on SDG&E’s TO5 filing. The settlement agreement provided for a ROE of 10.60%, consisting of a base ROE of 10.10% plus an additional 50 bps for participation in the California ISO (the California ISO adder). If the FERC issues an order ruling that California IOUs are no longer eligible for the California ISO adder, SDG&E would refund the California ISO adder as of the refund effective date
(June 1, 2019) if such a refund is determined to be required by the terms of the TO5 settlement. The TO5 term is effective June 1, 2019 and shall remain in effect each calendar quarter until terminated by a notice at least six months before the end of the calendar year. In 2020, SDG&E recorded retroactive revenues of $12 million related to 2019, and additional FERC revenues of $17 million to conclude a rate base matter, net of certain refunds to be paid to CPUC-jurisdictional customers.

Energy Efficiency Program Inquiry
In January 2020, the CPUC issued a ruling seeking comments on a report prepared by its consultant regarding SDG&E’s Upstream Lighting Program for the program year 2017. The CPUC subsequently expanded the scope of the comments to cover the program year 2018. The Upstream Lighting Program was one of SDG&E’s Energy Efficiency Programs designed to produce energy efficiency savings for which SDG&E could earn a performance-based incentive.
Pursuant to the CPUC ruling, intervenors representing ratepayers questioned SDG&E’s management of the program and alleged that certain program expenditures did not benefit the purpose of the program. As a result of the inquiry, SDG&E voluntarily expanded its review to include the program year 2019. Based on this review, SDG&E concluded that some concessions were appropriate, which include refunding certain costs to customers and reducing certain performance-based incentives. Accordingly, in the year ended December 31, 2020, SDG&E reduced revenues by $51 million and recorded a fine of $6 million in Other (Expense) Income, Net, on the Statement of Operations. The after-tax impact for the year ended December 31, 2020 was $44 million. In October 2020, SDG&E executed a settlement agreement with intervenors consistent with these concessions. In September 2021, the CPUC approved the settlement agreement.
NOTE 5. DEBT AND CREDIT FACILITIES

SHORT-TERM DEBT

Committed Line of Credit
At December 31, 2021, SDG&E had an aggregate capacity of $1.5 billion from a committed line of credit, which provides liquidity and support our commercial paper program. Because our commercial paper program is supported by the line of credit, we reflect the amount of commercial paper outstanding, before reductions of any unamortized discounts, and any letters of credit outstanding as a reduction to the available unused credit capacity.
COMMITTED LINE OF CREDIT
(Dollars in millions)
At December 31, 2021
Borrower
Expiration date of facility
Total facility
Commercial
paper
outstanding
Amounts outstanding
Available
unused credit
SDG&E
May 2024$1,500 $(401)$— $1,099 

The principal terms of our committed line of credit reflected in the table above include the following:
The facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in any facility.
The facility provides for the issuance of $100 million of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, SDG&E has the right to increase its letter of credit commitment up to $250 million.
Borrowings bear interest at a benchmark rate plus a margin that varies with SDG&E’s credit ratings.
SDG&E must maintain a ratio of indebtedness to total capitalization (as defined in the credit facility) of no more than 65% at the end of each quarter. At December 31, 2021, SDG&E was in compliance with this ratio under its credit facility.
Uncommitted Letters of Credit
Outside of our credit facility, we have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements.
UNCOMMITTED LETTERS OF CREDIT
(Dollars in millions)
December 31, 2021
Expiration date range
Uncommitted letters of
credit outstanding
SDG&E
January 2022 to May 2022$15 

Term Loan
In June 2021, we entered into a $375 million, 364-day term loan with a maturity date of June 27, 2022. At December 31, 2021, $375 million, net of negligible issuance costs, was outstanding under the term loan. The borrowing bears interest at benchmark rates plus 62.5 bps. The term loan provides SDG&E with additional liquidity outside of its line of credit.

WEIGHTED-AVERAGE INTEREST RATES
The weighted-average interest rates on the total short-term debt at December 31 were as follows:
WEIGHTED-AVERAGE INTEREST RATES
December 31,
20212020
SDG&E
0.65 %0.95 %
LONG-TERM DEBT
The following table shows the detail and maturities of long-term debt outstanding:
LONG-TERM DEBT AND FINANCE LEASES
(Dollars in millions)
December 31,
20212020
First mortgage bonds (collateralized by plant assets):
3% August 15, 2021$— $350 
1.914% payable 2015 through February 202217 53 
3.6% September 1, 2023450 450 
2.5% May 15, 2026500 500 
6% June 1, 2026250 250 
1.7% October 1, 2030800 800 
5.875% January and February 2034(1)
— — 
5.35% May 15, 2035250 250 
6.125% September 15, 2037250 250 
4% May 1, 2039(1)
— — 
6% June 1, 2039300 300 
5.35% May 15, 2040250 250 
4.5% August 15, 2040500 500 
3.95% November 15, 2041250 250 
4.3% April 1, 2042250 250 
3.75% June 1, 2047400 400 
4.15% May 15, 2048400 400 
4.1% June 15, 2049400 400 
3.32% April 15, 2050400 400 
2.95% August 15, 2051750 — 
6,417 6,053 
Finance lease obligations:
Purchased-power contracts
1,217 1,237 
Other
57 39 
1,274 1,276 
7,691 7,329 
Current portion of long-term debt
(49)(411)
Unamortized discount on long-term debt
(17)(13)
Unamortized debt issuance costs
(44)(39)
Total
7,581 6,866 
(1)Callable long-term debt not subject to make-whole provisions
MATURITIES OF LONG-TERM DEBT(1)
(Dollars in millions)
2022$17 
2023450 
2024— 
2025— 
2026750 
Thereafter
5,200 
Total
$6,417 
(1)Excludes finance lease obligations, discounts, and debt issuance costs.

SDG&E does not have unsecured long-term obligations at December 31, 2021.

Callable Long-Term Debt
At our option, certain debt at December 31, 2021 is callable subject to premiums:
CALLABLE LONG-TERM DEBT
(Dollars in millions)
Not subject to make-whole provisions
$— 
Subject to make-whole provisions
6,417 

First Mortgage Bonds
We issue first mortgage bonds secured by liens on our utility plant assets. We may issue additional first mortgage bonds if in compliance with the provisions of our bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $7.3 billion at December 31, 2021.
In August 2021, we issued $750 million of 2.95% green first mortgage bonds maturing in 2051 and received proceeds of $737 million, net of debt discount, underwriting discounts and debt issuance costs of $13 million. We intend to use the net proceeds to finance or refinance eligible projects that fall into one or more of the following categories: climate change adaptation, clean energy solutions and clean transportation.
Other Long-Term Debt
On February 18, 2022, we entered into a $400 million, two-year term loan with a maturity date of February 18, 2024. We may request up to three borrowings for an aggregate amount of $400 million through May 18, 2022. On February 18, 2022, we borrowed $200 million. The borrowing bears interest at benchmark rates plus 62.5 bps. The margin is based on our long-term senior unsecured credit rating.
NOTE 6. INCOME TAXES
We provide our calculations of ETRs in the following table.
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Years ended December 31,
202120202019
Income tax expense
$201 $190 $171 
Income before income taxes
$1,020 $1,014 $938 
Effective income tax rate
20 %19 %18 %

For SDG&E, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. The following items are subject to flow-through treatment:
repairs expenditures related to a certain portion of utility plant fixed assets
the equity portion of AFUDC, which is non-taxable
a portion of the cost of removal of utility plant assets
utility self-developed software expenditures
depreciation on a certain portion of utility plant assets
state income taxes
We present in the table below reconciliations of net U.S. statutory federal income tax rates to our ETRs.
RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES
Years ended December 31,
202120202019
U.S. federal statutory income tax rate21 %21 %21 %
State income taxes, net of federal income tax benefit
Depreciation
Excess deferred income taxes outside of ratemaking— — (3)
Self-developed software expenditures(1)(4)(3)
Amortization of excess deferred income taxes(2)(1)(1)
Allowance for equity funds used during construction(2)(2)(1)
Repairs expenditures(4)(3)(3)
Other, net
— — (1)
Effective income tax rate
20 %19 %18 %

The remeasurement of deferred income tax balances in December 2017, as a result of the TCJA, resulted in excess deferred income taxes that previously had been collected from ratepayers at the higher rate. In a January 2019 decision, the CPUC directed certain excess deferred income tax balances generated by activities outside of ratemaking be allocated to shareholders rather than ratepayers. As a result, in 2019, SDG&E recorded income tax benefits of $31 million from the release of a portion of the regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances.
The table below summarizes the effects of the TCJA remeasurement at December 31, 2017, by FERC account and jurisdiction.
TCJA REMEASUREMENT – REDUCTION TO DEFERRED INCOME TAX BALANCES
(Dollars in millions)
Year ended December 31, 2017
FERC ACs
182.3/254
FERC AC
190(1)(2)
FERC AC
282
FERC AC
283(3)
Total Deferred
FERC AC
410(Exp)
FERC$599 $$(421)$(183)$(599)$— 
CPUC829 (474)(361)(829)— 
Shareholder— 26 — 28 (28)
Total$1,428 $13 $(869)$(544)$(1,400)$(28)
(1)Since the table is summarizing a reduction to the net deferred income tax liability balance, the decrease to the 190 deferred tax asset account in this table is shown as positive.
(2)Does not include the net operating loss deferred tax asset related to FERC Transmission.
(3)Account 283 includes approximately $500 million of gross-up required under ASC 740 on flow-through deferred taxes and gross-up on excess deferred taxes.
In the first quarter of 2018, we made a $38 million true-up primarily related to the gross-up on flow-through deferred taxes required under ASC 740, Income Taxes. This resulted in additional reduction of deferred tax liabilities and an increase in net regulatory liabilities. In the first quarter of 2019, we reclassed $31 million of certain excess deferred taxes out of regulatory liabilities and into Shareholder, because these items were not related to plant in service nor were they part of the reduction to rate base for accumulated deferred income taxes.
The table below represents the amount of protected and unprotected excess deferred income taxes related to plant in service (excluding gross-up) as of December 31, 2021, 2020, 2019, 2018 and 2017.
TOTAL COMPANY EXCESS DEFERRED INCOME TAXES FOR PLANT IN SERVICE(1)
(Dollars in millions)
Year ended December 31
20212020201920182017
FERC - Protected$366 $371 $380 $382 $384 
CPUC - Protected441 450 457 463 469 
FERC - Unprotected(2)
(7)
CPUC - Unprotected(3)
(118)(117)(118)(120)(122)
Total$682 $710 $720 $728 $737 
(1)Does not include the net operating loss deferred tax asset related to FERC Transmission.
(2)Includes prior year true-up to excess deferred income tax balance and an adjustment to reclass certain Transmission-related excess deferred income taxes between Protected and Unprotected pursuant to FERC Order 864.
(3)Includes prior true-up to excess deferred income tax balance.
For plant in service, we use the Average Rate Assumption Method (ARAM) to amortize the excess deferred income taxes over the book life of the underlying property. During 2019, we received a final decision from the CPUC in our general rate case directing us to use straight-line amortization over a six-year period for certain unprotected items, and allowing us to track any differences between using ARAM and using the six-year straight-line amortization for these unprotected items. During 2021, we decided we would no longer contest the CPUC’s treatment of these unprotected items, which resulted in increased amortization in 2021. The CPUC decision also allowed us to track differences related to the inclusion of new cost of removal accruals in the ARAM calculation. As of December 31, 2021, we have not received a final regulatory order from the FERC regarding how customer rates should be reduced for excess deferred income taxes. Future potential regulatory orders and IRS guidance could impact our classification of protected and unprotected amounts indicated above, as well as the inclusion of new cost of removal accruals in the ARAM calculation.
Under ARAM, we reduced our regulatory liability related to excess deferred income taxes by $19 million, $10 million, $8 million, and $9 million in 2021, 2020, 2019, and 2018 respectively, excluding gross-up. The reduction in the excess deferred income tax regulatory liability (FERC AC 254) was offset against deferred income taxes (FERC AC 411.1). The table below reflects these adjustments for the following FERC accounts as of December 31, 2021, 2020, 2019, and 2018.

ARAM - REGULATORY LIABILITY / DEFERRED INCOME TAXES
(Dollars in millions)
Years ended December 31,
2021202020192018Amortization Period
FERC ACs 254/411.1
FERC - Protected
$$$$Book Depreciation Life
CPUC - ProtectedBook Depreciation Life
FERC - UnprotectedBook Depreciation Life
CPUC - Unprotected(2)(2)(2)Book Depreciation Life
Total$19 $10 $$

3.0
The components of income tax expense are as follows.
INCOME TAX EXPENSE
(Dollars in millions)
Years ended December 31,
202120202019
Current:
U.S. federal
$35 $121 $35 
U.S. state
13 34 31 
Total
48 155 66 
Deferred:
U.S. federal
99 11 75 
U.S. state
54 25 32 
Total
153 36 107 
Deferred investment tax credits
— (1)(2)
Total income tax expense
$201 $190 $171 
NOTES TO FINANCIAL STATEMENTS (Continued)

The table below presents the components of deferred income taxes:
DEFERRED INCOME TAXES
(Dollars in millions)
December 31,
20212020
Deferred income tax liabilities:
Differences in financial and tax bases of utility plant and other assets
$1,970 $1,833 
Regulatory balancing accounts
323 224 
Right-of-use assets – operating leases
52 28 
Property taxes
35 34 
Other
Total deferred income tax liabilities
2,381 2,121 
Deferred income tax assets:
Tax credits
Postretirement benefits— 14 
Compensation-related items12 12 
Operating lease liabilities52 28 
Bad debt allowance16 18 
State income taxes
Accrued expenses not yet deductible16 14 
Other
Total deferred income tax assets
106 102 
Net deferred income tax liability
$2,275 $2,019 

Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31:
RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
202120202019
Balance at January 1
$13 $12 $11 
Increase in prior period tax positions
Balance at December 31
$14 $13 $12 
Of December 31 balance, amounts related to tax positions that if recognized
in future years would:
Decrease the effective tax rate(1)
$(11)$(10)$(9)
Increase the effective tax rate(1)
(1)Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.
It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following:
POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS
(Dollars in millions)
At December 31,
202120202019
Potential resolution of audit issues with various U.S. federal, state and local
taxing authorities
$$$

Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in Income Tax Expense on the Statement of Operations. SDG&E accrued negligible amounts for interest expense and penalties at December 31, 2021 and 2020 on the Balance Sheet, and recorded negligible amounts of interest expense and penalties in the Statement of Operations for all periods presented.

INCOME TAX AUDITS
SDG&E is subject to U.S. federal income tax and state income tax and remains subject to examination for U.S. federal tax years after 2017 and state tax years after 2012
NOTE 7. EMPLOYEE BENEFIT PLANS
For our employee benefit plans, we:
recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the balance sheet;
measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year; and
recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.
The detailed information presented below covers the employee benefit plans of primarily Sempra and its consolidated subsidiaries.
Sempra has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E, which collectively cover all eligible employees, including a member of the Sempra board of directors who was a participant in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.
Sempra also has PBOP plans, including separate plans for SDG&E, which collectively cover all employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits.
Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans.

RABBI TRUST
In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $567 million and $512 million at December 31, 2021 and 2020, respectively.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

Benefit Plan Amendments Affecting 2019
In 2019, certain executive participants in a company nonqualified pension plan became eligible in this same plan for Supplemental Executive Retirement Plan benefits. This was treated as a plan amendment and increased the recorded pension liability by $3 million in 2019.

Benefit Obligations and Assets
The following table provides a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2021 and 2020, and a statement of the funded status at December 31, 2021 and 2020:
PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
Pension benefits
Other postretirement
benefits
2021202020212020
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1$913 $895 $193 $177 
Service cost35 31 
Interest cost25 30 
Contributions from plan participants— — 
Actuarial (gain) loss (2)37 (3)17 
Plan amendments— — — — 
Benefit payments(17)(18)(19)(20)
Settlements(69)(52)— — 
Transfer of liability from other plans— (10)— 
Net obligation at December 31885 913 188 193 
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1819 739 213 197 
Actual return on plan assets73 94 (5)26 
Employer contributions53 52 
Contributions from plan participants— — 
Benefit payments(17)(18)(19)(20)
Settlements(69)(52)— — 
Transfer of assets from other plans— — 
Fair value of plan assets at December 31859 819 197 213 
Funded status at December 31
$(26)$(94)$$20 
Net recorded (liability) asset at December 31
$(26)$(94)$$20 
Actuarial losses (gains) fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and Other Postretirement Benefit Plans” and updates to census data. In 2021, 2020 and 2019, the Society of Actuaries released updated mortality improvement projection scales, reflecting changes to projected observed longevity improvements in its mortality tables. We have incorporated these assumptions, adjusted for the Sempra companies’ actual mortality experience, in our calculations for each of those years.
Actuarial gains in pension plans in 2021 were driven primarily by an increase in discount rates. These actuarial gains were partially offset by actuarial losses due to an increase in the interest crediting rate for the cash balance plans due to updated census data.
Actuarial gains in PBOP plans in 2021 were driven primarily by an increase in discount rates.

Net Assets and Liabilities
The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. SDG&E recognizes realized and unrealized investment gains and losses during the current year.
We use the 10% corridor accounting method. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The 10% corridor accounting method helps mitigate volatility of net periodic benefit costs from year to year.
Defined benefit pension and other postretirement plans with an aggregated overfunded status are recognized as an asset and with an aggregated underfunded status are recognized as a liability; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. We record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on decisions by regulatory agencies.
We record annual pension and other postretirement net periodic benefit costs equal to the contributions to our qualified plans as authorized by the CPUC. The annual contributions to the pension plans are the greater of:
a minimum required funding amount as required by the IRS;
the amount required to maintain an 85% Adjusted Funding Target Attainment Percentage as defined by the Pension Protection Act of 2006, as amended; or
beginning January 1, 2019 and for the duration of the 2019 GRC cycle, a fixed amount equal to the estimated annual service cost as defined by U.S. GAAP plus one year of a 14-year amortization of the unfunded projected benefit obligation of the pension plan as of January 1, 2019, and limited to an annual amount that keeps the fair value of the pension plan assets from exceeding 110% of the pension benefit obligation of the plan.
The annual contributions to PBOP plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and PBOP plans. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.
The net (liability) asset is included in the following categories on the Balance Sheet at December 31:
PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS
(Dollars in millions)
Pension benefits
Other postretirement
benefits
2021202020212020
Noncurrent assets
$— $— $$20 
Current liabilities
(1)(2)— — 
Noncurrent liabilities
(25)(92)— — 
Net recorded (liability) asset
$(26)$(94)$$20 

Amounts recorded in AOCI at December 31, net of income tax effects and amounts recorded as regulatory assets, are as follows:
AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Pension benefits
20212020
Net actuarial loss
$(9)$(8)
Prior service cost
$(1)$(2)
Total
$(10)$(10)

The following table shows the obligations of funded pension plan with benefit obligations in excess of plan assets. At December 31, 2021, the assets for SDG&E’s funded pension plan exceeded the plan’s obligations.
OBLIGATIONS OF FUNDED PENSION PLANS
(Dollars in millions)
2020
Projected benefit obligation
$887 
Accumulated benefit obligation
834 
Fair value of plan assets
819 

The following table shows SDG&E’s obligations of unfunded pension plans at December 31:

OBLIGATIONS OF UNFUNDED PENSION PLANS
(Dollars in millions)
20212020
Projected benefit obligation
$26 $26 
Accumulated benefit obligation
22 22 

SDG&E has a funded other postretirement benefit plan. At December 31, 2021, the assets for SDG&E’s other postretirement benefit plan exceeded the plan’s obligations.
Net Periodic Benefit Cost
The following tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31:
NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
Pension benefits
Other postretirement benefits
202120202019202120202019
NET PERIODIC BENEFIT COST
Service cost$35 $31 $30 $$$
Interest cost25 30 34 
Expected return on assets(50)(49)(38)(10)(10)(11)
Amortization of:
Prior service cost— — 
Actuarial loss (gain)11 (2)(3)(2)
Settlement charges— — — — — 
Net periodic benefit cost (credit)19 17 40 (2)(3)— 
Regulatory adjustment34 38 14 — 
Total expense recognized
53 55 54 — — — 
CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OCI
Net loss— — — 
Prior service cost— — — — — 
Transfer of actuarial gain— (7)
Transfer of prior service credit— (5)— — — — 
Amortization of actuarial loss— (1)— — — — 
Amortization of prior service cost(1)(1)(1)— — — 
Total recognized in OCI
— (8)— — — 
Total recognized in net periodic benefit cost and OCI
$53 $47 $60 $— $— $— 

Assumptions for Pension and Other Postretirement Benefit Plans

Benefit Obligation and Net Periodic Benefit Cost
We develop the discount rate assumptions using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flows to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of corporate bonds with a Bloomberg Composite of AA or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plans’ projected benefit payments discounted at this rate with the market value of the bonds selected.
Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.
Interest crediting rate is based on an average 30-year Treasury bond from the month of November of the preceding year.
We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP.
The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:
WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION
AT DECEMBER 31
Pension benefits
Other postretirement benefits
2021202020212020
Discount rate
2.99 %2.73 %3.05 %2.85 %
Interest crediting rate(1)(2)
1.94 1.62 1.94 1.62 
Rate of compensation increase
3.50-10.00
2.70-10.00
3.50-10.00
2.70-10.00
(1)Interest crediting rate for pension benefits applies only to funded cash balance plans.
(2)Interest crediting rate for other postretirement benefits applies only to interest bearing health retirement accounts.

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST
YEARS ENDED DECEMBER 31
Pension benefits
Other postretirement benefits
202120202019202120202019
Discount rate
2.73 %3.44 %4.29 %2.85 %3.55 %4.30 %
Expected return on plan assets
6.25 7.00 7.00 4.81 5.51 6.92 
Interest crediting rate(1)(2)
1.62 2.28 3.36 1.62 2.28 3.36 
Rate of compensation increase
2.70-10.00
2.70-10.00
2.00-10.00
2.70-10.00
2.70-10.00
2.00-10.00
(1)Interest crediting rate for pension benefits applies only to funded cash balance plans.
(2)Interest crediting rate for other postretirement benefits applies only to interest bearing health retirement accounts.

Health Care Cost Trend Rates
Assumed health care cost trend rates have a significant effect on the amounts that we report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans:
ASSUMED HEALTH CARE COST TREND RATES
AT DECEMBER 31
Other postretirement benefit plans
Pre-65 retirees
Retirees aged 65 years and older
202120202019202120202019
Health care cost trend rate assumed for next year
6.00 %6.00 %6.25 %4.75 %4.75 %4.75 %
Rate to which the cost trend rate is assumed to decline (the ultimate trend)
4.75 %4.75 %4.75 %4.50 %4.50 %4.50 %
Year the rate reaches the ultimate trend
2025
2025
2025
2022
2022
2022

Plan Assets
Investment Allocation Strategy for Sempra’s Pension Master Trust
Sempra’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. Sempra maintains additional trusts, as we discuss below, including for certain of SDGE’s PBOP plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra.
The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. We assess the portfolio performance by comparing actual returns with relevant benchmarks. Currently, the pension plans’ target asset allocations are:
31% domestic equity
21% international equity
21% long credit
10% diversified real assets
10% return-seeking credit
5% ultra-long duration government securities
2% other diversifying assets
The asset allocation of the plans is reviewed by Sempra’s Plan Funding Committee and Pension and Benefits Investment Committee (the Committees) on a regular basis. When evaluating strategic asset allocations, the Committees consider many variables, including:
long-term cost
variability and level of contributions
funded status
a range of expected outcomes over varying confidence levels
This allocation results in a 74% target allocation to return-seeking assets and a 26% target allocation to risk-mitigating assets. We maintain asset allocations at strategic levels with reasonable bands of variance.
In accordance with the Sempra pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.
Rate of Return Assumption
The expected return on assets in our pension and PBOP plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date. We arrive at a 6.75% expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between 4% and 12% on return-seeking assets and between 1% and 4% for risk-mitigating assets. Certain trusts that hold assets for the SDG&E other postretirement benefit plan are subject to taxation, which impacts the expected after-tax return on assets in the plan.
Concentration of Risk
Plan assets are diversified across global equity and bond markets, and concentration of risk in any one economic, industry, maturity or geographic sector is limited.
Investment Strategy for SDG&E’s Other Postretirement Benefit Plans
SDG&E’s PBOP plans are funded by cash contributions from SDG&E and its current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association trusts. Certain assets of SDG&E’s PBOP plans are held in the pension master trust, which invests a portion of the assets in completion portfolios that aim to reduce interest rate risk, thereby resulting in an overall target allocation of 38% to return-seeking assets and 62% to risk-mitigating assets for these well-funded plans. SDG&E’s assets held in other Voluntary Employee Beneficiary Association trusts are invested in accordance with a de-risking glidepath that reduces the assets’ exposure to risk as the trusts become better funded. These specific allocations are periodically reviewed to help ensure that plan assets are best positioned to meet plan obligations.
Fair Value of Pension and Other Postretirement Benefit Plan Assets
We classify the investments in the trusts for SDG&E’s PBOP plans based on the fair value hierarchy, except for certain investments measured at NAV.
The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.
Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.
Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Other investments are valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.
Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.
Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.
Venture Capital Funds and Real Estate Funds – These funds consist of investments in venture capital funds and real estate funds that are held by limited partnerships or similar private entities following various investment strategies. The value is determined based on the NAV of our proportionate ownership interest in the entity.
Derivative Financial Instruments – Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index futures contracts are valued at the last sales price quoted on the exchange on which they primarily trade.
While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
We provide more discussion of fair value measurements in Notes 1 and 10. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis.
SDG&E holds a proportionate share of investment assets in the pension master trust at Sempra. The fair values of our pension plan assets by asset category are as follows:
FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
Fair value at December 31, 2021
Level 1
Level 2
Total
Sempra Energy Consolidated:
Cash and cash equivalents
$18 $— $18 
Equity securities:
Domestic
844 849 
International
384 385 
Registered investment companies
Domestic
204 21 225 
International
33 — 33 
Fixed income securities:
Domestic government and government agencies 463 24 487 
International government bonds— 11 11 
Domestic corporate bonds— 413 413 
International corporate bonds— 65 65 
Other— 
Total investment assets in the fair value hierarchy
$1,947 $540 2,487 
Accounts receivable/payable, net
(20)
Investments measured at NAV:
Common/collective trusts657 
Venture capital funds and real estate funds58 
Total investment assets
$3,182 
SDG&E’s proportionate share of investment assets
$859 
SoCalGas’ proportionate share of investment assets
$2,095 
Fair value at December 31, 2020
Level 1
Level 2
Total
Sempra Energy Consolidated:
Cash and cash equivalents
$$— $
Equity securities:
Domestic
931 — 931 
International
563 — 563 
Registered investment companies
Domestic
151 37 188 
International
32 — 32 
Fixed income securities:
Domestic government and government agencies238 34 272 
International government bonds— 13 13 
Domestic corporate bonds— 418 418 
International corporate bonds— 61 61 
Other(1)
Total investment assets in the fair value hierarchy
$1,924 $562 2,486 
Accounts receivable/payable, net
13 
Investments measured at NAV:
Common/collective trusts493 
Venture capital funds and real estate funds10 
Total investment assets
$3,002 
SDG&E’s proportionate share of investment assets
$819 
SoCalGas’ proportionate share of investment assets
$1,969 
The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SDG&E’s PBOP plan trusts are as follows:

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
Fair value at December 31, 2021
Level 1
Level 2
Total
Equity securities:
Domestic
$16 $— $16 
International
— 
Registered investment companies
Domestic
82 83 
International
— 
Fixed income securities:
Domestic government bonds
24 25 
Domestic corporate bonds
— 
Registered investment companies
— 
Total investment assets in the fair value hierarchy
138 11 149 
Accounts receivable/payable, net
(1)
Investments measured at NAV – Common/collective trusts
49 
Total investment assets
$197 
Fair value at December 31, 2020
Level 1
Level 2
Total
Equity securities:
Domestic
$17 $— $17 
International
11 — 11 
Registered investment companies
Domestic
69 76 
International
11 — 11 
Fixed income securities:
Domestic government bonds
38 40 
Domestic corporate bonds
— 
Registered investment companies
— 
Total investment assets in the fair value hierarchy
146 18 164 
Accounts receivable/payable, net
(2)
Investments measured at NAV – Common/collective trusts
51 
Total investment assets
$213 
Future Payments
We expect to contribute the following amounts to our pension and PBOP plans in 2022:
EXPECTED CONTRIBUTIONS
(Dollars in millions)
Pension plans
$52 
Other postretirement benefit plans

The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.
EXPECTED BENEFIT PAYMENTS
(Dollars in millions)
Pension
benefits
Other postretirement benefits
2022$71 $
202369 10 
202466 10 
202565 10 
202659 10 
2027-2031
275 48 

SAVINGS PLANS
Sempra, SDG&E and SoCalGas offer trusteed savings plans to all employees. Employee participation, employee contributions and employer matching contributions are subject to the provisions of the respective plans, and for employee contributions, limits imposed by the respective governmental authorities.
Employer contributions to the SDG&E savings plans were as follows:
EMPLOYER CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
202120202019
SDG&E
$18 $16 $15 

The market value of Sempra common stock held by the savings plans at Sempra, SDG&E and SoCalGas was $1.0 billion and $1.1 billion at December 31, 2021 and 2020, respectively.
NOTE 8. SHARE-BASED COMPENSATION

SEMPRA ENERGY EQUITY COMPENSATION PLANS
Sempra Energy has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra Energy. The plans permit a wide variety of share-based awards, including:
nonqualified stock options
incentive stock options
restricted stock awards
restricted stock units
stock appreciation rights
performance awards
stock payments
dividend equivalents
Eligible SDG&E employees participate in Sempra’s share-based compensation plans as a component of their compensation package.
In the three years ended December 31, 2021, Sempra had the following types of equity awards outstanding:
Nonqualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a three-year period and expire 10 years from the date of grant. Unvested option awards are subject to forfeiture following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.
Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra common stock at the end of three-year performance periods based on Sempra’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index (excluding water companies) and the S&P 500 Index. Sempra uses long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies (excluding water companies) to develop its targets for awards that vest based on EPS growth. These RSU awards are subject to forfeiture prior to vesting following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.
Up to an additional 100% of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.
For awards granted in 2016 and certain awards granted in 2017 and 2018 that vest based on Sempra’s total return to shareholders, a modifier adds 20% to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra and reduces the award’s payout by 20% for performance in the bottom quartile. However, in no event will more than an additional 100% of the granted RSUs be issued. If performance falls within the second or third quartiles, the modifier is not triggered, and the payout is based solely on total return to shareholders relative to that of specified market indices.
If Sempra’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis.
Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest ratably over three-year service periods (for awards granted after 2018), or at the end of three-year (for awards granted during 2016 through 2018) or four-year service periods (for awards granted prior to 2015). These awards are subject to earlier forfeiture upon termination of employment, subject to certain exceptions described below.
For awards that would otherwise be forfeited upon termination of employment, the Compensation and Talent Development Committee of Sempra’s board of directors may waive the forfeiture requirement and, with respect to options and service-based RSUs, may accelerate vesting. Awards are also subject to accelerated vesting upon a change in control under the applicable LTIP, in accordance with severance pay agreements or to the extent otherwise required by the terms of the applicable award. Dividend equivalents on shares subject to RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSUs to which the dividends relate.

SHARE-BASED AWARDS AND COMPENSATION EXPENSE
At December 31, 2021, 5,986,241 of Sempra common shares were authorized and available for future grants of share-based awards. Sempra’s practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.
Sempra measures and recognizes compensation expense for all share-based payment awards made to its employees and directors based on estimated fair values on the date of grant. Sempra recognizes compensation costs net of an estimated forfeiture rate (based on historical experience) and recognizes the compensation costs for nonqualified stock options and RSUs on a straight-line basis over the requisite service period of the award, which is generally three or four years. However, for awards granted to retirement-eligible participants, the expense is recognized over the initial year in which the award was granted as the award requires service through the end of the year in which it was granted. For awards granted to participants who become eligible for retirement during the requisite service period, the expense is recognized over the period between the date of grant and the later of the end of the year in which the award was granted or the date the participant first becomes eligible for retirement. Substantially all awards outstanding are classified as equity instruments; therefore, Sempra recognizes additional paid in capital as it recognizes the compensation expense associated with the awards. Sempra recognizes in earnings the tax benefits (or deficiencies) resulting from tax deductions that are in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments.
SDG&E records an expense for the plans to the extent that its employees participate in the Sempra plans and/or SDG&E is allocated a portion of the Sempra plans’ corporate staff costs. For SDG&E, total share-based compensation expense for share-based awards was comprised as follows:

SHARE-BASED COMPENSATION EXPENSE
(Dollars in millions)
Years ended December 31,
202120202019
Share-based compensation expense, before income taxes
$10 $11 $10 
Income tax benefit
(3)(3)(3)
$$$
Capitalized share-based compensation cost
$$$
Excess income tax deficiency
$(1)$(3)$

SEMPRA NONQUALIFIED STOCK OPTIONS
Sempra uses a Black-Scholes option-pricing model to estimate the fair value of each nonqualified stock option grant. The use of a valuation model requires it to make certain assumptions about selected model inputs. Expected volatility is calculated based on a blend of the historical and implied volatility of Sempra’s common stock price. The average expected term for options is based on the vesting schedule, contractual term of the option, expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected term estimated at the date of the grant. In 2021, 2020 and 2019, Sempra’s board of directors granted 222,620, 154,860 and 261,075 nonqualified stock options, respectively, that are exercisable over a three-year period. The weighted-average per-
share fair value for options granted was $19.07, $19.76 and $13.20 in 2021, 2020 and 2019, respectively. To calculate this fair value, Sempra used the Black-Scholes model with the following weighted-average assumptions:
KEY ASSUMPTIONS FOR STOCK OPTIONS GRANTED
Year ended December 31,
20212020
Stock price volatility
26.57 %18.78 %
Expected term
5.36 years
5.34 years
Risk-free rate of return
0.41 %1.68 %
Annual dividend yield
3.38 %2.60 %

The following table shows a summary of nonqualified stock options at December 31, 2021 and activity for the year then ended:
NONQUALIFIED STOCK OPTIONS
Common shares under options
Weighted- average exercise price
Weighted- average remaining contractual term (in years)
Aggregate intrinsic value (in millions)
Outstanding at January 1, 2021365,395 $120.93 
Granted222,620 $123.80 
Exercised(50,671)$106.76 
Outstanding at December 31, 2021537,344 $123.45 8.06 $
Vested or expected to vest at December 31, 2021537,344 $123.45 8.06 $
Exercisable at December 31, 2021152,189 $118.10 7.27 $

The aggregate intrinsic value at December 31, 2021 is the total of the difference between Sempra’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for nonqualified stock options exercised in the last three years was:
$1.4 million in 2021
$0.4 million in 2020
$4 million in 2019
Sempra expects a negligible amount of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2021 to be recognized over a weighted-average period of 1.1 years. The weighted-average per-share fair values for nonqualified stock options granted in 2020 and 2019 was $149.12 and $106.76, respectively.
Sempra received cash of $5 million, a negligible amount and $3 million from stock option exercises in 2021, 2020 and 2019, respectively.

SEMPRA RESTRICTED STOCK UNITS
Sempra uses a Monte-Carlo simulation model to estimate the fair value of its RSUs that vest based on Sempra’s total return to shareholders. Its determination of fair value is affected by the historical volatility of the common stock price for Sempra
and its peer group companies. The valuation also is affected by the risk-free rates of return and a number of other variables. Below are key assumptions for RSUs granted in the last three years:
KEY ASSUMPTIONS FOR RSUs GRANTED
Years ended December 31,
202120202019
Stock price volatility
33.39 %16.35 %17.74 %
Risk-free rate of return
0.16 %1.55 %2.46 %

The following table shows a summary of RSUs at December 31, 2021 and activity for the year then ended:
RESTRICTED STOCK UNITS
Performance-based
restricted stock units
Service-based
restricted stock units
Units
Weighted- average
grant-date
fair value
Units
Weighted- average
grant-date
fair value
Nonvested at January 1, 2021893,961$121.61 343,577$121.59 
Granted323,889$133.03 143,980$124.84 
Vested(317,128)$105.03 (202,352)$116.28 
Forfeited(29,945)$131.55 (7,905)$161.49 
Nonvested at December 31, 2021(1)
870,777$131.64 277,300$127.54 
Expected to vest at December 31, 2021854,697$131.47 271,197$127.47 
(1)Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, up to an additional 100% of the shares represented by the RSUs may be issued if Sempra Energy exceeds target performance conditions.

In 2021, 2020 and 2019, the total fair value of RSU shares vested during the year was $57 million, $70 million and $36 million, respectively.
Sempra expects $17 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2021 to be recognized over a weighted-average period of 1.5 years. The weighted-average per-share fair values for performance-based RSUs granted were $155.62 and $113.54 in 2020 and 2019, respectively. The weighted-average per-share fair values for service-based RSUs granted were $138.91 and $112.50 in 2020 and 2019, respectively.
NOTE 9. DERIVATIVE FINANCIAL INSTRUMENTS
We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposure is commodity market risk. Our use of derivatives for this risk is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that could cause our asset values to fall or our liabilities to increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.
In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.
In all other cases, we record derivatives at fair value on the Balance Sheet. We may have derivatives that are (1) cash flow hedges, (2) fair value hedges, or (3) undesignated. Depending on the applicability of hedge accounting and the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in OCI (cash flow hedges), on the balance sheet (regulatory offsets), or recognized in earnings (fair value hedges and undesignated derivatives not subject to rate recovery). We classify cash flows from the settlements of our derivative instruments as operating activities on the Statement of Cash Flows.

HEDGE ACCOUNTING
We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments . Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria.

ENERGY DERIVATIVES
Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:
We use natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed-price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Statement of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.
We are allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Statement of Operations.
From time to time, we may use other energy derivatives to hedge exposures such as GHG allowances.

The following table summarizes net energy derivative volumes.
NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
December 31,
Commodity
Unit of measure
20212020
Natural gas
MMBtu
716
Electricity
MWh
11
Congestion revenue rights
MWh
4543

FINANCIAL STATEMENT PRESENTATION
The Balance Sheet reflects the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Balance Sheet, including the amount of cash collateral receivables that were not offset because the cash collateral was in excess of liability positions.
DERIVATIVE INSTRUMENTS ON THE BALANCE SHEET
(Dollars in millions)
December 31, 2021
Other current
assets
Other long-term assets
Other current
liabilities
Deferred credits and other
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery
$34 $52 $(20)$— 
Associated offsetting commodity contracts
(5)— — 
Net amounts presented on the balance sheet
29 52 (15)— 
Additional cash collateral for commodity contracts
subject to rate recovery
28 — — — 
Total(1)
$57 $52 $(15)$— 
December 31, 2020
Other current
assets
Other long-term assets
Other current
liabilities
Deferred credits and other
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery
$32 $95 $(28)$(25)
Associated offsetting commodity contracts
(1)— — 
Net amounts presented on the balance sheet
31 95 (27)(25)
Additional cash collateral for commodity contracts
subject to rate recovery
24 — — — 
Total(1)
$55 $95 $(27)$(25)
(1)Included in Current Assets: Fixed-Price Contracts and Other Derivatives.

The following table summarizes the effects of derivative instruments not designated as hedging instruments on the Statement of Operations.
UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
Pretax gain (loss) on derivatives recognized in earnings
Years ended December 31,
Location
202120202019
Commodity contracts subject
to rate recovery
Cost of Electric Fuel
and Purchased Power
$31 $88 $(140)

CONTINGENT FEATURES
Certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization. SDG&E did not have this group of derivative instruments in a liability position at December 31, 2021 or 2020.
Some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above..
NOTE 10. FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASURES
The tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2021 and 2020. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair-valued assets and liabilities, and their placement within the fair value hierarchy.
The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 9 under “Financial Statement Presentation.”
The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).
Our financial assets and liabilities that were accounted for at fair value on a recurring basis in the tables below include the following:
Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding accounts receivable and accounts payable. A third-party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).
For commodity contracts, we primarily use a market or income approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions, as we discuss below in “Level 3 Information.”
Rabbi Trust investments include short-term investments that consist of money market and mutual funds that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1).
RECURRING FAIR VALUE MEASURES
(Dollars in millions)
Fair value at December 31, 2021
Level 1
Level 2
Level 3
Total
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents$13 $(10)$— $
Equity securities
358 $$— 364 
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies
48 — 56 
Municipal bonds
— 321 — 321 
Other securities
— 260 — 260 
Total debt securities
48 589 — 637 
Total nuclear decommissioning trusts(1)
419 585 — 1,004 
Commodity contracts subject to rate recovery
12 — 69 81 
Effect of netting and allocation of collateral(2)
22 — 28 
Total
$453 $585 $75 1,113 
Liabilities:
Commodity contracts subject to rate recovery
$— $— $15 $15 
Total
$— $— $15 $15 
Fair value at December 31, 2020
Level 1
Level 2
Level 3
Total
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents$$(6)$— $
Equity securities
358 — 364 
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies
41 24 — 269 
Municipal bonds
— 326 — 326 
Other securities
— 270 — 270 
Total debt securities
41 620 — 661 
Total nuclear decommissioning trusts(1)
408 620 — 1,028 
Commodity contracts subject to rate recovery
— 121 126 
Effect of netting and allocation of collateral(2)
18 — 24 
Total
$431 $620 $127 1,178 
Liabilities:
Commodity contracts subject to rate recovery
$— $— $52 $52 
Total
$— $— $52 $52 
(1)Excludes cash balances and cash equivalents.
(2)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Level 3 Information
The table below sets forth reconciliations of changes in the fair value of CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for SDG&E.
LEVEL 3 RECONCILIATIONS(1)
(Dollars in millions)
Years ended December 31,
202120202019
Balance at January 1
$69 $28 $179 
Realized and unrealized gains (losses)
(50)19 (184)
Allocated transmission instruments
Settlements
32 16 27 
Balance at December 31
$54 $69 $28 
Change in unrealized gains (losses) relating to
instruments still held at December 31
$(16)$34 $(139)
(1)Excludes the effect of the contractual ability to settle contracts under master netting agreements.

Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.
CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, were in the following ranges for the years indicated below:
CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS
Settlement year
Price per MWh
Median price per MWh
2022$(3.67)
to
6.96$(0.70)
2021(1.81)
to
14.11(0.12)
2020(3.77)
to
6.03(1.58)

The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 9.
Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. The range and weighted-average price of these inputs at December 31 were as follows:
LONG-TERM, FIXED-PRICE ELECTRICITY POSITIONS PRICE INPUTS
Settlement year
Price per MWh
Weighted-average price per MWh
2021$24.10 
to
$105.00 $53.57 
202019.60 
to
78.10 39.71 
A significant increase (decrease) in market electricity forward prices would result in a significantly higher (lower) fair value. We summarize long-term, fixed-price electricity position volumes in Note 9.
Realized gains and losses associated with CRRs and long-term, fixed-price electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Statement of Operations. Because unrealized gains and losses are recorded as regulatory assets and liabilities, they do not affect earnings.

Fair Value of Financial Instruments
The fair values of certain of our financial instruments (cash, accounts receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Balance Sheet.
FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
Carrying
Fair value
amount
Level 1
Level 2
Level 3
Total
December 31, 2021
Total long-term debt(1)
$6,417 $— $7,236 $— $7,236 
December 31, 2020
Total long-term debt(1)
$6,053 $— $7,184 $— $7,184 
(1)Before reductions of unamortized discount and debt issuance costs of $61 and $52 at December 31, 2021 and 2020, respectively, and excluding finance lease obligations of $1,274 and $1,276 at December 31, 2021 and 2020, respectively.

We provide the fair values for the securities held in the NDT related to SONGS in Note 12.
NOTE 11. PREFERRED STOCK
SDG&E is authorized to issue up to 45 million shares of preferred stock, respectively. At December 31, 2021 and 2020, SDG&E had no preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by SDG&E’s board of directors at the time of issuance.
NOTE 12. SAN ONOFRE NUCLEAR GENERATING STATION
SDG&E has a 20% ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which permanently ceased operations in June 2013 after an extended outage as a result of issues with the steam generators used in the facility. Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.
SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in SDG&E’s Statement of Operations.

NUCLEAR DECOMMISSIONING AND FUNDING
As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Major decommissioning work began in 2020. We expect the majority of the decommissioning work to take approximately 10 years. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be completed once Units 2 and 3 are dismantled and the spent fuel is removed from the site. The spent fuel is currently being stored on-site, until the DOE identifies a spent fuel storage facility and puts in place a program for the fuel’s disposal, as we discuss below. SDG&E is responsible for approximately 20% of the total decommissioning cost.
The Samuel Lawrence Foundation filed a writ petition under the California Coastal Act in LA Superior Court in December 2019 seeking to invalidate the coastal development permit and to obtain injunctive relief to stop decommissioning work. The petition was denied in September 2021. In December 2021, the foundation filed a notice of appeal. In September 2020, the foundation filed another writ petition under the California Coastal Act in LA Superior Court seeking to set aside the CCC’s July 2020 approval of the inspection and maintenance plan for the SONGS’ canisters and to obtain injunctive relief to stop decommissioning work. In December 2021, the foundation filed a request for dismissal. To date, decommissioning work has not been interrupted as a result of these writ petitions.
In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. Amounts that were collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. SDG&E classifies debt and equity securities held in the NDT as available-for-sale. The NDT assets are presented on the Balance Sheet at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.
Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In December 2021, SDG&E received authorization from the CPUC to access NDT funds of up to $78 million for forecasted 2022 costs.
In September 2020, the IRS and the U.S. Department of the Treasury published final regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The final regulations adopted most of the provisions of the proposed regulations issued in December 2016. The final regulations apply to taxable years ending on or after September 4, 2020 and confirm that the definition of “nuclear decommissioning costs” includes amounts related to the storage of spent nuclear fuel at both on-site and off-site ISFSIs.
The final regulations also clarify that costs incurred for ISFSIs that may be or are expected to be reimbursed by the DOE may be paid or reimbursed from a qualified trust fund. Accordingly, the final regulations allow SDG&E the option to access qualified trust funds to recover spent fuel storage costs before Edison reaches final settlement with the DOE regarding the
DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below.

Nuclear Decommissioning Trusts
The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT on the Balance Sheet. We provide additional fair value disclosures for the NDT in Note 10.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
Cost
Gross
unrealized
gains
Gross
unrealized
losses
Estimated
fair
value
At December 31, 2021:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies(1)
$56 $— $— $56 
Municipal bonds(2)
309 13 (1)321 
Other securities(3)
255 (2)260 
Total debt securities
620 20 (3)637 
Equity securities
104 262 (2)364 
Short-term investments, primarily cash equivalents— — 
Receivables (payables), net— — 
Total
$735 $282 $(5)$1,012 
At December 31, 2020:
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies
$64 $$— $65 
Municipal bonds
308 18 — 326 
Other securities
253 17 — 270 
Total debt securities
625 36 — 661 
Equity securities
112 254 (2)364 
Short-term investments, primarily cash equivalents— — 
Receivables (payables), net(9)— — (9)
Total
$731 $290 $(2)$1,019 
(1)Maturity dates are 2022-2052.
(2)Maturity dates are 2022-2056.
(3)Maturity dates are 2022-2072.

The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.
SALES OF SECURITIES IN THE NDT
(Dollars in millions)
Years ended December 31,
202120202019
Proceeds from sales
$961 $1,439 $914 
Gross realized gains
67 156 24 
Gross realized losses
(5)(17)(5)
Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on SDG&E’s Balance Sheet. We determine the cost of securities in the trusts on the basis of specific identification.

ASSET RETIREMENT OBLIGATION
The present value of SDG&E’s ARO related to decommissioning costs for all three SONGS units was $568 million at December 31, 2021 and is based on a cost study prepared in 2020, which will be submitted to the CPUC in the first half of 2022. The ARO for Units 2 and 3 reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $79 million in 2022, $66 million in 2023, $77 million in 2024, $46 million in 2025, $52 million in 2026, and $718 million thereafter.

U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL
Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC. The ISFSI will operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.
The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. In November 2019, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from January 2017 through July 2018, which is pending DOE approval. It is unclear when Edison will pursue litigation claims for spent fuel management costs incurred on or after August 1, 2018. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.

NUCLEAR INSURANCE
SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $110 million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $450 million insurance limit, this additional coverage would be available to provide a total of $560 million in coverage limits per incident.
The SONGS owners have nuclear property damage insurance of $130 million, which exceeds the minimum federal requirements of $50 million. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $4.3 million of retrospective premiums based on overall member claims.
The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act) of $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.
NOTE 13. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS
We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed, and in some cases have exceeded, applicable insurance coverage and could materially adversely affect our business, results of operations, financial condition, cash flows and/or prospects. Unless otherwise indicated, we are unable to reasonably estimate possible losses or a range of losses in excess of any amounts accrued.
At December 31, 2021, loss contingency accruals for legal matters that are probable and estimable were $4 million. We discuss our policy regarding accrual of legal fees in Note 1.
Ordinary Course Litigation
We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.

LEASES
A lease exists when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. We determine if an arrangement is or contains a lease at inception of the contract.
Some of our lease agreements contain nonlease components, which represent activities that transfer a separate good or service to the lessee. As the lessee for both operating and finance leases, we have elected to combine lease and nonlease components as a single lease component for real estate, fleet vehicles, power generating facilities, and pipelines, whereby fixed or in-substance fixed payments allocable to the nonlease component are accounted for as part of the related lease liability and ROU asset. As the lessor, we have elected to combine lease and nonlease components as a single lease component for real estate and power generating facilities if the timing and pattern of transfer of the lease and nonlease components are the same and the lease component would be classified as an operating lease if accounted for separately.

Lessee Accounting
We have operating and finance leases for real and personal property (including office space, land, fleet vehicles, machinery and equipment, warehouses and other operational facilities) and PPAs with renewable energy, energy storage and peaker plant facilities.
Some of our leases include options to extend the lease terms for up to 20 years. Our lease liabilities and ROU assets are based on lease terms that may include such options when it is reasonably certain that we will exercise the option.
Certain of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. We do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. In such cases, we recognize short-term lease costs on a straight-line basis over the lease term. Our short-term lease costs for the period reasonably reflect our short-term lease commitments.
Certain of our leases contain escalation clauses requiring annual increases in rent ranging from 2% to 3% or based on the Consumer Price Index. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year. Variable lease payments that are based on an index or rate are included in the initial measurement of our lease liability and ROU asset based on the index or rate at lease commencement and are not remeasured because of changes to the index or rate. Rather, changes to the index or rate are treated as variable lease payments and recognized in the period in which the obligation for those payments is incurred.
Similarly, PPAs for the purchase of renewable energy require lease payments based on a stated rate per MWh produced by the facilities, and we are required to purchase substantially all the output from the facilities. SDG&E is required to pay
additional amounts for capacity charges and actual purchases of energy that exceed the minimum energy commitments. Under these contracts, we do not recognize a lease liability or ROU asset for leases for which there are no fixed lease payments. Rather, these variable lease payments are recognized separately as variable lease costs. SDG&E estimates these variable lease payments to be $297 million in 2022, $296 million in 2023, $297 million in 2024, $296 million in 2025, $290 million in 2026 and $2,779 million thereafter.
As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We also record a corresponding ROU asset, initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. We test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.
For our operating leases, we recognize a single lease cost on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.
For our finance leases, the interest expense on the lease liability and amortization of the ROU asset are accounted for separately. We recognize amortization of the ROU asset on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.
Our leases do not contain any material residual value guarantees, restrictions or covenants.
Classification of ROU assets and lease liabilities and the weighted-average remaining lease term and discount rate associated with operating and finance leases are summarized in the table below.
LESSEE INFORMATION ON THE BALANCE SHEET
(Dollars in millions)
December 31,
20212020
Right-of-use assets:
Operating leases:
ROU assets (included in Capital Lease Accounts)$185 $102 
Finance leases:
PP&E1,381 1,356 
Accumulated depreciation(107)(80)
PP&E, net1,274 1,276 
Total ROU assets$1,459 $1,378 
Lease liabilities:
Operating leases:
Other current liabilities(1)
$26 $27 
Deferred credits and other(2)
159 73 
185 100 
Finance leases:
Current portion of long-term debt and finance leases(1)
32 26 
Long-term debt and finance leases(2)
1,242 1,250 
1,274 1,276 
Total lease liabilities$1,459 $1,376 
Weighted-average remaining lease term (in years):
Operating leases11 
Finance leases17 19 
Weighted-average discount rate:
Operating leases3.22 %3.62 %
Finance leases14.48 %14.65 %
(1)Reflected as Obligations under Capital Lease – Current for FERC reporting.
(2)Reflected as Obligations under Capital Lease – Noncurrent for FERC reporting.
The table below presents the maturity analysis of our lease liabilities and reconciliation to the present value of lease liabilities:

LESSEE MATURITY ANALYSIS OF LIABILITIES
(Dollars in millions)
December 31, 2021
Operating leases(1)
Finance leases(2)
2022$30 $197 
202327 197 
202425 192 
202516 188 
202615 188 
Thereafter
105 2,279 
Total undiscounted lease payments
218 3,241 
Less: imputed interest
(33)(1,967)
Total lease liabilities
185 1,274 
Less: current lease liabilities
(26)(32)
Long-term lease liabilities
$159 $1,242 
(1)Includes $9 in each of 2022 through 2026 and $87 thereafter related to purchased-power contracts.
(2)Substantially all amounts are related to purchased-power contracts.

Leases that Have Not Yet Commenced
SDG&E has entered into three energy storage tolling agreements, of which it expects two will commence in the third quarter of 2022 and one will commence in the second quarter of 2023. SDG&E expects to account for these agreements as operating leases upon commencement and expects the future minimum lease payments to be $8 million in 2022, $17 million in 2023, $18 million in each of 2024 through 2026 and $101 million thereafter until expiration at various dates from 2032 through 2033.
.
CONTRACTUAL COMMITMENTS

Natural Gas Contracts
SoCalGas has responsibility for procuring natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas buys natural gas under short-term and long-term contracts for this portfolio from various producing regions in the southwestern U.S., U.S. Rockies and Canada.
SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2032.

Purchased-Power Contracts
For 2022, SDG&E expects to meet its customer power requirements from the following resource types:
Long-term contracts: 60% (of which 57% is provided by renewable energy contracts expiring on various dates through 2042)
Other SDG&E-owned generation and tolling contracts expiring on various dates through 2039: 46%
Spot market sales: (6)%
Payments on our purchased-power contracts could exceed the minimum commitments based on energy needs. At December 31, 2021, the future minimum payments under long-term purchased-power contracts for SDG&E are as follows:
FUTURE MINIMUM PAYMENTS – PURCHASED-POWER CONTRACTS
(Dollars in millions)
2022$218 
2023188 
2024162 
2025105 
2026100 
Thereafter
817 
Total minimum payments(1)
$1,590 
(1)Excludes purchase agreements accounted for as finance leases.

Payments on these contracts represent capacity charges and minimum energy and transmission purchases that exceed the minimum commitment. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. SDG&E estimates these variable payments to be $63 million in each of 2022 through 2026 and $430 million thereafter. Total payments under purchased-power contracts for SDG&E were $495 million in 2021, $534 million in 2020 and $744 million in 2019.

Construction and Development Projects
At December 31, 2021, SDG&E has commitments to make future payments of $27 million for construction projects that include:
$4 million for infrastructure improvements for electric and natural gas transmission and distribution systems; and
$23 million related to spent fuel management at SONGS.
SDG&E expects future payments under these contractual commitments to be $3 million in each of 2022 and 2023, $1 million in each of 2024 through 2026 and $18 million thereafter.

OTHER COMMITMENTS
We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 12.
Fire Mitigation Fund
In connection with the completion of the Sunrise Powerlink project in 2012, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments, for which a liability has been recorded, are expected to be $4 million per year in 2022 through 2026 and $275 million thereafter, subject to escalation of 2% per year, for a remaining 48-year period. At December 31, 2021, the present value of these future payments of $122 million has been recorded as a regulatory asset as the amounts represent a cost that we expect will be recovered from customers in the future.
Franchise Agreements
In December 2020, the City of San Diego and SDG&E agreed to extend SDG&E’s natural gas and electric franchises for the city to June 1, 2021. After completing a competitive bid process, on June 8, 2021, the City of San Diego approved ordinances granting to SDG&E the natural gas and electric franchises for the city. These franchise agreements provide SDG&E the opportunity to serve the City of San Diego for the next 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewal with a supermajority vote. The agreements went into effect in July 2021. Over the 20-year term of the agreements, SDG&E will make principal payments of $110 million and interest payments of $13 million as consideration for the natural gas and electric franchise agreements. The consideration paid will not be recovered from customers and will be amortized over 20 years. SDG&E paid $11 million to the City of San Diego in 2021. At December 31, 2021, SDG&E has commitments to make future payments of $14 million per year in 2022 through 2024, $15 million in 2025, $4 million in 2026 and $51 million thereafter.
Two lawsuits have been filed in the California Superior Court challenging the City’s process for its award of the natural gas and electric franchises and seeking to declare the franchise agreements null and void.

ENVIRONMENTAL ISSUES
Our operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a PRP under the federal Superfund laws and similar state laws.
In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Our costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates.
We disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions, exclusive of interest and costs, exceed the lesser of $1 million or 1% of current assets, which was $14 million at December 31, 2021.
Other Environmental Issues
We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:
CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES
(Dollars in millions)
Years ended December 31,
202120202019
SDG&E
$32 $39 $39 

Our costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.
The environmental issues currently facing us include (1) investigation and remediation of manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by us at which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.
The table below shows the status at December 31, 2021 of our manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:
STATUS OF ENVIRONMENTAL SITES
# Sites
complete(1)
# Sites
in process
Manufactured-gas sites
3
Third-party waste-disposal sites
2
1
(1)There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

We record environmental liabilities when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary.
The following table shows our accrued liabilities for environmental matters at December 31, 2021.
ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
Manufactured-
gas sites
Waste
disposal
sites (PRP)(1)
Other hazardous waste sites
Total(2)
SDG&E(3)
$— $$12 $18 
(1)Sites for which we have been identified as a PRP.
(2)Includes $1 million classified as current liabilities, and $4 million classified as noncurrent liabilities on SDG&E’s Balance Sheet.
(3)Does not include SDG&E’s liability for SONGS marine environment mitigation.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the CCC to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 12, does not reduce SDG&E’s mitigation obligation. SDG&E’s share of the estimated mitigation costs is $97 million, of which $53 million has been incurred through December 31, 2021 and $44 million is accrued for remaining costs through 2053, which is recoverable in rates and included in noncurrent Regulatory Assets on the Balance Sheet.
We expect future payments related to our environmental liabilities on an undiscounted basis to be $2 million in each of 2022 through 2025, $14 million in 2026 and $40 million thereafter.
Subsequent Events
We evaluated events and transactions that occurred after December 31, 2021 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation.
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
GLOSSARY
2019 GRC FDfinal decision in SDG&E’s 2019 General Rate Case
ABCalifornia Assembly Bill
AFUDCallowance for funds used during construction
AMPArrearage Management Payment Plan
AOCIaccumulated other comprehensive income (loss)
AROasset retirement obligation
ASCAccounting Standards Codification
ASUAccounting Standards Update
bpsbasis points
CARBCalifornia Air Resources Board
CCCCalifornia Coastal Commission
CCMcost of capital adjustment mechanism
COVID-19coronavirus disease 2019
CPUCCalifornia Public Utilities Commission
CRRcongestion revenue right
DOEU.S. Department of Energy
DWRCalifornia Department of Water Resources
EdisonSouthern California Edison Company, a subsidiary of Edison International
EnovaEnova Corporation
EPSearnings (losses) per common share
ESJEnergía Sierra Juárez, S. de R.L. de C.V.
ETReffective income tax rate
FERCFederal Energy Regulatory Commission
GHGgreenhouse gas
GRCGeneral Rate Case
IOUinvestor-owned utility
IRSU.S. Internal Revenue Service
ISFSIindependent spent fuel storage installation
ISOIndependent System Operator
LA Superior CourtLos Angeles County Superior Court
MMBtumillion British thermal units (of natural gas)
Moody’sMoody’s Investors Service
MWmegawatt
MWhmegawatt hour
NAVnet asset value
NDTnuclear decommissioning trusts
NEILNuclear Electric Insurance Limited
NRCNuclear Regulatory Commission
O&Moperation and maintenance expense
OCIother comprehensive income (loss)
OEISOffice of Energy Infrastructure Safety
OIROrder Instituting a Rulemaking
OMECOtay Mesa Energy Center
PBOPpostretirement benefits other than pension
PG&EPacific Gas and Electric Company
PP&Eproperty, plant and equipment
PPApower purchase agreement
PRPPotentially Responsible Party
RECrenewable energy certificate
ROEreturn on equity
ROUright-of-use
GLOSSARY
RPSRenewables Portfolio Standard
RSUrestricted stock unit
S&PS&P Global Ratings, a division of S&P Global Inc.
SDG&ESan Diego Gas & Electric Company
SECU.S. Securities and Exchange Commission
SempraSempra Energy doing business as Sempra, together with its consolidated entities unless otherwise stated or indicated by the context
SoCalGasSouthern California Gas Company
SONGSSan Onofre Nuclear Generating Station
TCJATax Cuts and Jobs Act of 2017
TO4Electric Transmission Owner Formula Rate, effective through May 31, 2019
TO5Electric Transmission Owner Formula Rate, effective June 1, 2019
U.S. GAAPgenerally accepted accounting principles in the United States of America
Wildfire Fundthe fund established pursuant to AB 1054
Wildfire LegislationAB 1054 and AB 111


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
  1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
  2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
  3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
  4. Report data on a year-to-date basis.
Line No.
Item
(a)
Unrealized Gains and Losses on Available-For-Sale Securities
(b)
Minimum Pension Liability Adjustment (net amount)
(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow Hedges Interest Rate Swaps
(f)
Other Cash Flow Hedges [Specify]
(g)
Totals for each category of items recorded in Account 219
(h)
Net Income (Carried Forward from Page 116, Line 78)
(i)
Total Comprehensive Income
(j)
1
Balance of Account 219 at Beginning of Preceding Year
15,874,048
15,874,048
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
3
Preceding Quarter/Year to Date Changes in Fair Value
5,839,946
5,839,946
4
Total (lines 2 and 3)
5,839,946
5,839,946
824,492,862
830,332,808
5
Balance of Account 219 at End of Preceding Quarter/Year
10,034,102
10,034,102
6
Balance of Account 219 at Beginning of Current Year
10,034,102
10,034,102
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
8
Current Quarter/Year to Date Changes in Fair Value
82,938
82,938
9
Total (lines 7 and 8)
82,938
82,938
(a)
819,252,902
819,169,964
10
Balance of Account 219 at End of Current Quarter/Year
10,117,040
10,117,040


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: NetIncomeLoss
South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.

Line No.
Classification
(a)
Total Company For the Current Year/Quarter Ended
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other (Specify)
(g)
Common
(h)
1
UtilityPlantAbstract
UTILITY PLANT
2
UtilityPlantInServiceAbstract
In Service
3
UtilityPlantInServiceClassified
Plant in Service (Classified)
23,327,823,836
18,107,371,442
3,200,655,070
2,019,797,324
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
1,649,438,076
1,412,542,088
236,895,988
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
0
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
0
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
0
8
UtilityPlantInServiceClassifiedAndUnclassified
Total (3 thru 7)
24,977,261,912
19,519,913,530
3,200,655,070
2,256,693,312
9
UtilityPlantLeasedToOthers
Leased to Others
112,194,000
112,194,000
10
UtilityPlantHeldForFutureUse
Held for Future Use
0
11
ConstructionWorkInProgress
Construction Work in Progress
1,670,246,956
1,110,158,230
202,750,290
357,338,436
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
3,750,722
3,750,722
13
UtilityPlantAndConstructionWorkInProgress
Total Utility Plant (8 thru 12)
26,763,453,590
20,746,016,482
3,403,405,360
2,614,031,748
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
(a)
8,253,275,451
6,345,189,796
946,127,200
961,958,455
15
UtilityPlantNet
Net Utility Plant (13 less 14)
18,510,178,139
14,400,826,686
2,457,278,160
1,652,073,293
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
7,314,136,707
5,966,016,105
936,724,642
411,395,960
19
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService
Amortization and Depletion of Producing Natural Gas Land and Land Rights
0
20
AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService
Amortization of Underground Storage Land and Land Rights
0
21
AmortizationOfOtherUtilityPlantUtilityPlantInService
Amortization of Other Utility Plant
905,166,125
345,201,072
9,402,558
550,562,495
22
DepreciationAmortizationAndDepletionUtilityPlantInService
Total in Service (18 thru 21)
8,219,302,832
6,311,217,177
946,127,200
961,958,455
23
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract
Leased to Others
24
DepreciationUtilityPlantLeasedToOthers
Depreciation
31,472,139
31,472,139
25
AmortizationAndDepletionUtilityPlantLeasedToOthers
Amortization and Depletion
0
26
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers
Total Leased to Others (24 & 25)
31,472,139
31,472,139
27
DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract
Held for Future Use
28
DepreciationUtilityPlantHeldForFutureUse
Depreciation
0
29
AmortizationUtilityPlantHeldForFutureUse
Amortization
0
30
DepreciationAndAmortizationUtilityPlantHeldForFutureUse
Total Held for Future Use (28 & 29)
0
31
AbandonmentOfLeases
Abandonment of Leases (Natural Gas)
0
32
AmortizationOfPlantAcquisitionAdjustment
Amortization of Plant Acquisition Adjustment
2,500,480
2,500,480
33
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Total Accum Prov (equals 14) (22,26,30,31,32)
(b)
8,253,275,451
6,345,189,796
946,127,200
961,958,455


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking
Accumulated Provision for Depreciation & Amortization Classified
under FERC Seven Factor Test
In Accordance with Guidelines in FERC Order 888

Accumulated Provision
Electric
Intangible Plant 173,963,956 
Steam Production Plant 305,885,272 
Other Production Plant 272,588,028 
Transmission Plant 1,635,135,373 
Distribution Plant 3,606,168,212 
General Plant 219,537,534 
Ratemaking Electric 6,213,278,375 
Nuclear Decommissioning 1,011,036,365 
ASC 410 (FAS 143 and FIN 47) - Electric (1,018,731,937)
Capital Leases A/D 90,279,107 
Leased to Others- Citizens A/D (Sunrise) 29,238,086 
Leased to Others- Citizens A/D (SX-PQ) 2,234,053 
Cuyamaca Permanent Adjustment 17,855,747 
Total Electric 6,345,189,796 
Ratemaking Gas 1,161,217,848 
FIN 47 - Gas (215,090,648)
Total Gas 946,127,200 
Ratemaking Common 857,931,943 
FIN 47 - Common 2,922,489 
Capital Lease A/D 101,104,023 
Total Common 961,958,455 
Total Accumulated Provision EOQ 12/2021 8,253,275,451 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production 293,178,925 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production 284,106,681 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant 1,544,320,791 
(b) Concept: AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Reclassification as of 12/2021 Accum. Provision for Depreciation & Amortization for Ratemaking
Accumulated Provision for Depreciation & Amortization Classified
under FERC Seven Factor Test
In Accordance with Guidelines in FERC Order 888

Accumulated Provision
Electric
Intangible Plant 173,963,956 
Steam Production Plant 305,885,272 
Other Production Plant 272,588,028 
Transmission Plant 1,635,135,373 
Distribution Plant 3,606,168,212 
General Plant 219,537,534 
Ratemaking Electric 6,213,278,375 
Nuclear Decommissioning 1,011,036,365 
ASC 410 (FAS 143 and FIN 47) - Electric (1,018,731,937)
Capital Leases A/D 90,279,107 
Leased to Others- Citizens A/D (Sunrise) 29,238,086 
Leased to Others- Citizens A/D (SX-PQ) 2,234,053 
Cuyamaca Permanent Adjustment 17,855,747 
Total Electric 6,345,189,796 
Ratemaking Gas 1,161,217,848 
FIN 47 - Gas (215,090,648)
Total Gas 946,127,200 
Ratemaking Common 857,931,943 
FIN 47 - Common 2,922,489 
Capital Lease A/D 101,104,023 
Total Common 961,958,455 
Total Accumulated Provision EOQ 12/2021 8,253,275,451 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Steam Production 293,178,925 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Other Production 284,106,681 
Total 13-Month Average Accum. Provision as of 12/31/2021 -Transmission Plant 1,544,320,791 

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
  1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent.
  2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.
Description of item
(a)
Balance Beginning of Year
(b)
Changes during Year Additions
(c)
Changes during Year Amortization
(d)
Changes during Year Other Reductions (Explain in a footnote)
(e)
Balance End of Year
(f)
1
Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2
Fabrication
3
Nuclear Materials
4
Allowance for Funds Used during Construction
5
(Other Overhead Construction Costs, provide details in footnote)
6
SUBTOTAL (Total 2 thru 5)
7
Nuclear Fuel Materials and Assemblies
8
In Stock (120.2)
9
In Reactor (120.3)
10
SUBTOTAL (Total 8 & 9)
11
Spent Nuclear Fuel (120.4)
12
Nuclear Fuel Under Capital Leases (120.6)
13
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
15
Estimated Net Salvage Value of Nuclear Materials in Line 9
16
Estimated Net Salvage Value of Nuclear Materials in Line 11
17
Est Net Salvage Value of Nuclear Materials in Chemical Processing
18
Nuclear Materials held for Sale (157)
19
Uranium
20
Plutonium
21
Other (Provide details in footnote)
22
TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
  1. Report below the original cost of electric plant in service according to the prescribed accounts.
  2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
  3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
  4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments.
  5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
  6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of the prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year.
  7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.
  8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages.
  9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End of Year
(g)
1
1. INTANGIBLE PLANT
2
(301) Organization
3
(302) Franchise and Consents
222,841
222,841
4
(303) Miscellaneous Intangible Plant
191,341,267
569,423
17,094
191,893,596
5
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
191,564,108
569,423
17,094
192,116,437
6
2. PRODUCTION PLANT
7
A. Steam Production Plant
8
(310) Land and Land Rights
14,526,518
14,526,518
9
(311) Structures and Improvements
91,410,208
21,264
1,318
91,430,154
10
(312) Boiler Plant Equipment
162,192,323
2,865,019
672
165,056,670
11
(313) Engines and Engine-Driven Generators
12
(314) Turbogenerator Units
131,402,613
1,338,434
1,500
132,739,547
13
(315) Accessory Electric Equipment
86,962,688
797
86,961,891
14
(316) Misc. Power Plant Equipment
59,602,710
5,286,153
2,685
64,886,178
15
(317) Asset Retirement Costs for Steam Production
5,259,070
3,303,758
1,955,312
16
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
551,356,130
9,510,870
3,310,730
557,556,270
17
B. Nuclear Production Plant
18
(320) Land and Land Rights
19
(321) Structures and Improvements
20
(322) Reactor Plant Equipment
21
(323) Turbogenerator Units
22
(324) Accessory Electric Equipment
23
(325) Misc. Power Plant Equipment
24
(326) Asset Retirement Costs for Nuclear Production
25
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26
C. Hydraulic Production Plant
27
(330) Land and Land Rights
28
(331) Structures and Improvements
29
(332) Reservoirs, Dams, and Waterways
30
(333) Water Wheels, Turbines, and Generators
31
(334) Accessory Electric Equipment
32
(335) Misc. Power Plant Equipment
33
(336) Roads, Railroads, and Bridges
34
(337) Asset Retirement Costs for Hydraulic Production
35
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36
D. Other Production Plant
37
(340) Land and Land Rights
226,796
226,796
38
(341) Structures and Improvements
24,812,767
127,058
359
1,000
24,940,466
39
(342) Fuel Holders, Products, and Accessories
22,279,073
80
22,278,993
40
(343) Prime Movers
105,365,778
166,380
691
105,531,467
41
(344) Generators
366,763,275
9,126,937
38,248,482
80,809
1,000
337,559,921
42
(345) Accessory Electric Equipment
33,767,456
129,106
10
33,896,552
43
(346) Misc. Power Plant Equipment
40,164,692
29,128,792
2,683
69,290,801
44
(347) Asset Retirement Costs for Other Production
44.1
(348) Energy Storage Equipment - Production
45
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
593,379,837
38,678,273
38,248,482
84,632
593,724,996
46
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
1,144,735,967
48,189,143
38,248,482
3,395,362
1,151,281,266
47
3. Transmission Plant
48
(350) Land and Land Rights
252,442,567
4,009,991
1,551
256,451,007
48.1
(351) Energy Storage Equipment - Transmission
49
(352) Structures and Improvements
669,356,121
82,918,323
195,778
193,935
35,702
751,849,029
50
(353) Station Equipment
1,966,465,850
209,901,233
1,667,653
576,604
1,396,399
2,172,726,427
51
(354) Towers and Fixtures
922,725,564
6,653,764
3,955
929,375,373
52
(355) Poles and Fixtures
930,750,214
59,371,599
7,684,894
387,241
11
982,049,689
53
(356) Overhead Conductors and Devices
821,798,414
47,516,727
1,919,462
105,037
140,894
867,149,748
54
(357) Underground Conduit
550,520,796
10,355,756
388,314
560,488,238
55
(358) Underground Conductors and Devices
557,705,658
12,712,430
345,656
570,072,432
56
(359) Roads and Trails
370,697,495
9,872,611
411,184
380,158,922
57
(359.1) Asset Retirement Costs for Transmission Plant
928,663
4,639,851
5,568,514
58
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)
7,043,391,342
443,312,434
11,467,787
2,226,374
1,572,984
7,475,889,379
59
4. Distribution Plant
60
(360) Land and Land Rights
110,481,006
4,210,681
5,191
1,396
114,687,892
61
(361) Structures and Improvements
12,303,450
962,349
904
240
13,264,655
62
(362) Station Equipment
617,985,881
44,983,038
1,217,011
44,381
321,782
661,385,745
63
(363) Energy Storage Equipment – Distribution
125,965,956
56,804,921
21,285
182,749,592
64
(364) Poles, Towers, and Fixtures
941,396,761
115,627,829
23,148,506
82,165
130,864
1,033,663,055
65
(365) Overhead Conductors and Devices
974,345,978
193,551,872
7,876,954
82,168
556,168
1,159,382,560
66
(366) Underground Conduit
1,598,054,522
124,992,054
1,899,720
36,743
23,868,557
1,697,241,556
67
(367) Underground Conductors and Devices
1,763,177,307
213,864,845
11,707,090
2,511,620
26,741,936
1,994,588,618
68
(368) Line Transformers
752,621,931
46,277,655
3,259,202
29,321
795,611,063
69
(369) Services
620,724,886
88,937,539
1,658,225
41,923
1,859,305
706,102,972
70
(370) Meters
273,059,948
14,687,470
755,553
140
286,991,725
71
(371) Installations on Customer Premises
74,443,380
537,620
15,382
6,938
6,207
74,952,473
72
(372) Leased Property on Customer Premises
73
(373) Street Lighting and Signal Systems
34,064,775
1,796,850
65,672
3,126
326
35,792,501
74
(374) Asset Retirement Costs for Distribution Plant
25,092,921
12,325,699
12,767,222
75
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
7,923,718,702
907,234,723
51,609,410
10,161,113
1,273
8,769,181,629
76
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77
(380) Land and Land Rights
78
(381) Structures and Improvements
79
(382) Computer Hardware
80
(383) Computer Software
81
(384) Communication Equipment
82
(385) Miscellaneous Regional Transmission and Market Operation Plant
83
(386) Asset Retirement Costs for Regional Transmission and Market Oper
84
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85
6. General Plant
86
(389) Land and Land Rights
7,312,143
7,312,143
87
(390) Structures and Improvements
45,611,646
24,478
118,133
45,469,035
88
(391) Office Furniture and Equipment
89
(392) Transportation Equipment
58,146
58,146
90
(393) Stores Equipment
46,522
490
46,032
91
(394) Tools, Shop and Garage Equipment
37,634,714
3,490,439
228,053
115
40,896,985
92
(395) Laboratory Equipment
5,336,019
5,336,019
93
(396) Power Operated Equipment
60,529
60,529
94
(397) Communication Equipment
387,968,334
27,475,567
287,150
302,598
1,570,604
416,424,757
95
(398) Miscellaneous Equipment
3,204,867
114,293
12,045
11,689
3,654
3,299,080
96
SUBTOTAL (Enter Total of lines 86 thru 95)
487,232,920
31,080,299
527,248
339,370
1,456,125
518,902,726
97
(399) Other Tangible Property
98
(399.1) Asset Retirement Costs for General Plant
99
TOTAL General Plant (Enter Total of lines 96, 97, and 98)
487,232,920
31,080,299
527,248
339,370
1,456,125
518,902,726
100
TOTAL (Accounts 101 and 106)
16,790,643,039
1,430,386,022
101,852,927
11,686,565
118,132
18,107,371,437
101
(102) Electric Plant Purchased (See Instr. 8)
102
(Less) (102) Electric Plant Sold (See Instr. 8)
103
(103) Experimental Plant Unclassified
104
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
16,790,643,039
1,430,386,022
101,852,927
11,686,565
118,132
(a)
18,107,371,437


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: ElectricPlantInService
Reclassification of 2021 Electric Plant-in-Service for Ratemaking
Plant in Service Classified under FERC Seven Factor Test
In Accordance with Guidelines in FERC Order 888




BOY 2021 EOY 2021
Intangible Plant 191,341,265  191,893,594 
Steam Production Plant 561,761,598  571,265,496 
Nuclear Production Plant —  —  *
Other Production Plant 537,020,375  537,622,612 
Transmission Plant 6,921,237,975  7,334,224,128 
Distribution Plant 8,046,663,231  8,919,066,814 
General Plant 487,232,916  518,902,724 
Ratemaking Electric 16,745,257,360  18,072,975,368 
ASC 410 (FAS 143 and FIN 47) 31,280,654  20,291,049 
Cuyamaca Permanent Adjustment 14,105,025  14,105,025 
Total Electric Plant-in-Service 16,790,643,039  18,107,371,442 
Total 13-Month Average Plant Balance for 2021 - Steam Production 566,175,050 
Total 13-Month Average Plant Balance for 2021 - Other Production 542,749,890 
Total 13-Month Average Plant Balance for 2021 - Transmission Plant 7,094,919,316 
* As a result of the SONGS plant closure, the December 2021 Nuclear Production Plant Balance is zero.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.
LesseeName
Name of Lessee
(a)
IndicationOfAssociatedCompany
* (Designation of Associated Company)
(b)
LeaseDescription
Description of Property Leased
(c)
CommissionAuthorization
Commission Authorization
(d)
ExpirationDateOfLease
Expiration Date of Lease
(e)
ElectricPlantLeasedToOthers
Balance at End of Year
(f)
1
Citizens Sunrise Transmission LLC
True
30 Mile-500KV Transmission Line
10/19/2012
07/02/2042
85,194,000
2
(Border-East Line)
3
Citizens Sycamore-Penasquitos
True
11.5 Mile-Underground 230KV
08/21/2019
06/01/2049
27,000,000
4
Transmission LLC
Transmission Line (Segment B)
47
TOTAL
112,194,000


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
  1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use.
  2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.
ElectricPlantHeldForFutureUseDescription
Description and Location of Property
(a)
ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Date Originally Included in This Account
(b)
ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Date Expected to be used in Utility Service
(c)
ElectricPlantHeldForFutureUse
Balance at End of Year
(d)
1 Land and Rights:
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
  1. Report below descriptions and balances at end of year of projects in process of construction (107).
  2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts).
  3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.
ConstructionWorkInProgressProjectDescription
Description of Project
(a)
ConstructionWorkInProgress
Construction work in progress - Electric (Account 107)
(b)
1
PALOMAR ENERGY CENTER OPERATIONAL ENHANCEMENTS
3,272,495
2
TL628 CABLE REPLACEMENT
1,210,047
3
TL6916 POLE REPLACEMENT
3,708,450
4
SAN MARCOS SUB REBUILD 69KV & 12 KV
1,306,900
5
TL13831 WOOD TO STEEL REPLACEMENT
4,284,564
6
TL694 WOOD TO STEEL REPLACEMENT
2,671,701
7
GENERATION HYDROGEN PROJECT
1,279,874
8
TL636 WOOD POLE REPLACEMENT
5,683,147
9
TL600 RELIABILITY POLE REPLACEMENTS
6,801,817
10
TL667 CABLE REPLACEMENT
1,822,930
11
GRANITE SUBSTATION 69KV LOOP-IN
3,384,388
12
POWAY SUBSTATION REBUILD
10,910,035
13
TL603B SWEETWATER TAP REMOVAL
7,939,057
14
TRANSMISSION FIBER OPTIC NETWORK
31,210,278
15
FALLBROOK BATTERY ENERGY STORAGE SYSTEM
1,715,588
16
OVERSTRESSED BREAKER REPLACEMENTS
8,754,968
17
TRANSMISSION TRAINING YARD EXPANSION
1,387,689
18
TL686 WARNERS-NARROWS POLE REPLACEMENT
7,159,332
19
TL674A RECONFIGURE
12,587,162
20
TL664 SOUTHBAY-SWEETWATER UPGRADE
7,497,306
21
TL691 WOOD TO STEEL REPLACEMENT
10,340,670
22
TL6975 ESCONDIDO - SAN MARCOS
15,658,569
23
TRANSMISSION SYSTEM AUTOMATION
13,836,438
24
MIGUEL SUB 230KV REBUILD
10,689,639
25
TL690 WOOD TO STEEL REPLACEMENT
8,880,052
26
TL673 CABLE REPLACE
23,321,168
27
TL695 SW POLE REPLACEMENT
11,488,982
28
TL13838 WOOD TO STEEL REPLACEMENT
2,106,297
29
TL615/659 CABLE REPLACEMENT
21,906,966
30
SUBSTATION RELIABILITY UPGRADE PROJECT
3,115,692
31
TL6926 RINCON-VALLEY CENTER POLE REPLACEMENT
87,463,002
32
CONDITION BASED MONITORING - CIRCUIT BREAKERS
9,405,700
33
TL605 RECONDUCTOR
6,100,858
34
SYNCHRONIZED PHASOR MEASUREMENT SYSTEM
1,888,922
35
MISSION 230KV REBUILD
9,028,537
36
SUBSTATION SECURITY PROJECTS
8,238,324
37
CRITICAL ASSET SECURITY
20,851,410
38
TRANSMISSION INFRASTRUCTURE IMPROVEMENTS
13,577,946
39
FIBER OPTIC FOR RELAY PROTECTION & TELECOMMUNICATION
25,821,878
40
TRANSMISSION COMPLIANCE PROGRAM
25,549,760
41
FIRE THREAT ZONE COMPLIANCE PROGRAM
4,799,309
42
MOBILE HOME PARK UTILITY UPGRADES
1,494,812
43
TL679 CUSTOMER RELOCATION
2,126,286
44
GRANITE SUBSTATION 12KV BREAKER REPLACEMENT
3,033,453
45
DRONE INVESTIGATION ASSESSMENT & REPAIR
3,124,745
46
TL23001 INSULATOR REPLACEMENT
3,613,197
47
HEAVY DUTY VEHICLE CHARGING INFRASTRUCTURE
3,219,264
48
TL13811 WOOD TO STEEL REPLACEMENT
1,001,173
49
POWER QUALITY PROGRAM
3,357,199
50
FALLBROOK BATTERY ENERGY STORAGE SYSTEM_1
6,487,782
51
TL639 POLE REPLACEMENT
2,325,359
52
URBAN SUBSTATION SWITCHGEAR REPLACEMENT
2,674,074
53
IV SUBSTATION SHUNT REPLACEMENT
1,487,203
54
DESERT STAR ENERGY CENTER
1,199,151
55
HFTD OVERHEAD EQUIPMENT REPLACEMENT
3,114,301
56
ARTESIAN 230KV SUBSTATION EXPANSION
54,996,438
57
NON-HFTD OVERHEAD EQUIPMENT REPLACEMENT
4,218,061
58
ORANGE COUNTY LONG RANGE PLAN
71,711,370
59
SUNCREST TERTIARY REACTOR REPLACEMENT
1,908,801
60
TEE MODERNIZATION PROGRAM
1,032,414
61
4KV MODERNIZATION
4,100,386
62
HFTD FUSE REPLACEMENTS
1,930,736
63
DOE SWITCH REPLACEMENT
5,533,813
64
DISTRIBUTION SYSTEM CAPACITY IMPROVEMENT
1,792,760
65
REACTIVE SMALL CAPITAL PROJECTS
1,753,211
66
UG DISTRIBUTION SERVICE MANAGEMENT
1,793,497
67
DISTRIBUTION SUBSTATION RELIABILITY
3,393,378
68
PSPS ENGINEERING ENHANCEMENTS
4,326,242
69
SAN MATEO SUB REBUILD
3,402,002
70
CORRECTIVE MAINTENANCE PROGRAM
3,187,961
71
NEW BUSINESS INFRASTRUCTURE
5,123,020
72
OBSOLETE SUBSTATION EQUIPMENT REPLACEMENT
1,752,552
73
CORRECTIVE MAINT. PROG. (CMP) UG SWITCH REPLAC. & MANHOLE REPAIR
1,203,928
74
UG NON-RESIDENTIAL NEW BUSINESS
7,161,423
75
NEW SERVICE INSTALLATIONS
4,490,973
76
OH DISTRIBUTION SERVICE MANAGEMENT
6,705,462
77
SUBSTATION BREAKER AND RELAY REPLACEMENTS
7,542,478
78
MID-COAST TROLLEY EXTENSION PROJECT
1,180,036
79
STREAMVIEW SUBSTATION 69/12KV REBUILD
4,744,958
80
UG RESIDENTIAL NEW BUSINESS
7,034,660
81
ELECTRIC DISTRIBUTION STREET & HIGHWAY RELOCATIONS
11,339,323
82
WOOD POLE REINFORCEMENT
6,960,118
83
C1047: NEW 12KV CIRCUIT
2,013,502
84
HFTD TIER 2 & 3 CMP POLE REPLACEMENTS
2,609,405
85
FIRE THREAT ZONE PROTECTION & SCADA UPGRADE
39,140,669
86
PURE WATER PROJECT
2,983,552
87
DISTRIBUTION SUBSTATION SCADA EXPANSION
1,480,466
88
CONVERSION FROM OH TO UG RULE 20A
12,921,381
89
BORREGO MICROGRID
4,854,679
90
GAS INSULATED SWITCH REPLACEMENT
1,934,999
91
C724: NEW 12KV CIRCUIT
10,518,704
92
OH PUBLIC SAFETY PROGRAM
12,629,174
93
DISTRIBUTION CIRCUIT RELIABILITY CONSTRUCTION
2,723,187
94
BACKUP POWER FOR RESILIENCY
10,098,642
95
TORREY PINES SUBSTATION 12KV BREAKER REPLACEMENT
2,561,964
96
EL CAJON SUBSTATION 12KV BREAKER REPLACEMENT
1,258,419
97
FIRE THREAT ZONE UNDERGROUNDING
46,855,890
98
C303 RECONDUCTOR
2,731,485
99
EV CHARGING STATIONS AT SCHOOLS
1,380,973
100
EV CHARGING STATIONS AT PUBLIC PARKS
3,609,270
101
KETTNER SUBSTATION REBUILD
2,877,864
102
MOBILE HOME PARK UTILITY CONVERSIONS
5,771,946
103
MISSION SUBSTATION 12KV BREAKER REPLACEMENT
1,578,394
104
ADVANCED ENERGY STORAGE UPGRADES
7,960,106
105
HFTD OVERHEAD DISTRIBTUION HARDENING
111,593,046
106
OH SYSTEM COVERED CONDUCTOR
30,911,041
107
KEARNY BATTERY ENERGY STORAGE PROJECT
23,957,110
108
RAMONA MICROGRID
4,709,321
109
BUTTERFIELD MICROGRID
1,423,076
110
C235 RECONDUCTOR
1,550,343
111
HELICOPTER INFRARED CAMERA
1,045,405
112
SDG&E SOLAR ENERGY PROGRAM
1,812,653
113
DATA FOUNDATION AND REPORTING
6,885,893
114
WILDFIRE SAFETY DIVISION SCHEMA PROJECT
7,100,242
115
WILDFIRE MGMT ASSESSMENT PLATFORM
7,102,751
116
DISTRIBUTION DEFERRAL OPPORTUNITY REPORTING
2,380,427
117
PERCENTAGE OF INCOME PAYMENT PLAN PROGRAM
2,089,314
118
UNALLOCATED CONSTRUCTION OVERHEADS & LABOR ACCRUAL
24,354,479
119
MINOR PROJECTS (LESS THAN $1,000,000)
30,188,673
43 Total
1,110,158,230


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
  1. Explain in a footnote any important adjustments during year.
  2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property.
  3. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications.
  4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.
Item
(a)
Total (c + d + e)
(b)
Electric Plant in Service
(c)
Electric Plant Held for Future Use
(d)
Electric Plant Leased To Others
(e)
Section A. Balances and Changes During Year
1
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Balance Beginning of Year
5,576,471,800
5,549,614,769
26,857,031
2
Depreciation Provisions for Year, Charged to
3
DepreciationExpenseExcludingAdjustments
(403) Depreciation Expense
603,127,309
(a)
603,127,309
4
DepreciationExpenseForAssetRetirementCosts
(403.1) Depreciation Expense for Asset Retirement Costs
5
ExpensesOfElectricPlantLeasedToOthers
(413) Exp. of Elec. Plt. Leas. to Others
4,615,108
4,615,108
6
TransportationExpensesClearing
Transportation Expenses-Clearing
7
OtherClearingAccounts
Other Clearing Accounts
8
OtherAccounts
Other Accounts (Specify, details in footnote):
9.1
Other Accounts (Specify, details in footnote):
10
DepreciationProvision
TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)
607,742,417
603,127,309
4,615,108
11
Net Charges for Plant Retired:
12
BookCostOfRetiredPlant
Book Cost of Plant Retired
101,847,734
(b)
101,847,734
13
CostOfRemovalOfPlant
Cost of Removal
86,663,119
86,663,119
14
SalvageValueOfRetiredPlant
Salvage (Credit)
1,955,010
1,955,010
15
NetChargesForRetiredPlant
TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)
186,555,843
186,555,843
16
OtherAdjustmentsToAccumulatedDepreciation
Other Debit or Cr. Items (Describe, details in footnote):
17.1
Other Debit or Cr. Items (Describe, details in footnote):
6,646,297
(c)
6,646,297
18
BookCostOfAssetRetirementCosts
Book Cost or Asset Retirement Costs Retired
6,476,167
6,476,167
19
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)
5,997,488,244
5,966,016,105
31,472,139
Section B. Balances at End of Year According to Functional Classification
20
AccumulatedDepreciationSteamProduction
Steam Production
300,114,066
300,114,066
21
AccumulatedDepreciationNuclearProduction
Nuclear Production
22
AccumulatedDepreciationHydraulicProductionConventional
Hydraulic Production-Conventional
23
AccumulatedDepreciationHydraulicProductionPumpedStorage
Hydraulic Production-Pumped Storage
24
AccumulatedDepreciationOtherProduction
Other Production
302,324,304
302,324,304
25
AccumulatedDepreciationTransmission
Transmission
1,659,773,187
1,628,301,048
31,472,139
26
AccumulatedDepreciationDistribution
Distribution
3,515,739,153
3,515,739,153
27
AccumulatedDepreciationRegionalTransmissionAndMarketOperation
Regional Transmission and Market Operation
28
AccumulatedDepreciationGeneral
General
219,537,534
219,537,534
29
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
TOTAL (Enter Total of lines 20 thru 28)
5,997,488,244
5,966,016,105
31,472,139


FOOTNOTE DATA

(a) Concept: DepreciationExpenseExcludingAdjustments
Depreciation Provision - Electric Only (Line 10, Pg 219) $ 603,127,309 
Depreciation Provision - Common Alloc. to Elec. (Line 11, Pg 336) 56,368,616 
Depreciation Provision - (Line 6, Col. G, Pg 115) $ 659,495,925 
(b) Concept: BookCostOfRetiredPlant
Book Cost of Plant Retired (Line 12, Col. B, Pg 219) $ (101,847,734)
Total Plant Retired (Line 100, Col. D, Pg 207) 101,852,927 
Adj. For Land & Intangible Retirements not impacting (5,193)
Difference $ — 
(c) Concept: OtherAdjustmentsToAccumulatedDepreciation
SONGS Decommissioning - Current Year Trust Income (Loss) $ (6,615,047)
Transfer of Reserve Balances between Departments (31,251)
Other Debit and Credit Items (Line 16, Pg 219) $ (6,646,298)

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
  1. Report below investments in Account 123.1, Investments in Subsidiary Companies.
  2. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal.
  3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1.
  4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge.
  5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number.
  6. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year.
  7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f).
  8. Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.
DescriptionOfInvestmentsInSubsidiaryCompanies
Description of Investment
(a)
DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Date Acquired
(b)
DateOfMaturityInvestmentsInSubsidiaryCompanies
Date of Maturity
(c)
InvestmentInSubsidiaryCompanies
Amount of Investment at Beginning of Year
(d)
EquityInEarningsOfSubsidiaryCompanies
Equity in Subsidiary Earnings of Year
(e)
InterestAndDividendRevenueFromInvestments
Revenues for Year
(f)
InvestmentInSubsidiaryCompanies
Amount of Investment at End of Year
(g)
InvestmentGainLossOnDisplosal
Gain or Loss from Investment Disposed of
(h)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Total Cost of Account 123.1 $
Total


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
MATERIALS AND SUPPLIES
  1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
  2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.
Account
(a)
Balance Beginning of Year
(b)
Balance End of Year
(c)
Department or Departments which Use Material
(d)
1
Fuel Stock (Account 151)
2
Fuel Stock Expenses Undistributed (Account 152)
3
Residuals and Extracted Products (Account 153)
4
Plant Materials and Operating Supplies (Account 154)
5
Assigned to - Construction (Estimated)
131,950,322
123,566,571
ELECTRIC/GAS
6
Assigned to - Operations and Maintenance
7
Production Plant (Estimated)
8
Transmission Plant (Estimated)
9
Distribution Plant (Estimated)
10
Regional Transmission and Market Operation Plant (Estimated)
11
Assigned to - Other (provide details in footnote)
9,947,003
9,314,998
ELECTRIC/GAS
12
TOTAL Account 154 (Enter Total of lines 5 thru 11)
141,897,325
132,881,569
13
Merchandise (Account 155)
14
Other Materials and Supplies (Account 156)
COMMON
15
Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16
Stores Expense Undistributed (Account 163)
COMMON
17
18
19
20
TOTAL Materials and Supplies
141,897,325
132,881,569


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Allowances (Accounts 158.1 and 158.2)
  1. Report below the particulars (details) called for concerning allowances.
  2. Report all acquisitions of allowances at cost.
  3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts.
  4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k).
  5. Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
  6. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
  7. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts).
  8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies.
  9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
  10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Current Year Year One Year Two Year Three Future Years Totals
Line No.
SO2 Allowances Inventory (Account 158.1)
(a)
No.
(b)
Amt.
(c)
No.
(d)
Amt.
(e)
No.
(f)
Amt.
(g)
No.
(h)
Amt.
(i)
No.
(j)
Amt.
(k)
No.
(l)
Amt.
(m)
1
Balance-Beginning of Year
144,627
144,627
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
12,947
12,947
12,947
12,947
349,569
401,357
5
Returned by EPA
6
7
8
Purchases/Transfers:
9
Transfers to Palomar
4
4
10
Transfers to Miramar
11
Transfers to Cuyamaca Peak
12
Transfers to Desert Star
1
1
13
14
15
Total
5
5
16
17
Relinquished During Year:
18
Charges to Account 509
19
Other:
20
Allowances Used
21
Cost of Sales/Transfers:
22
23
24
25
26
27
28
Total
29
Balance-End of Year
157,569
12,947
12,947
12,947
349,569
545,979
30
31
Sales:
32
Net Sales Proceeds(Assoc. Co.)
33
Net Sales Proceeds (Other)
34
Gains
35
Losses
Allowances Withheld (Acct 158.2)
36
Balance-Beginning of Year
37
Add: Withheld by EPA
38
Deduct: Returned by EPA
39
Cost of Sales
40
Balance-End of Year
41
42
Sales
43
Net Sales Proceeds (Assoc. Co.)
44
Net Sales Proceeds (Other)
45
Gains
46
Losses


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Allowances (Accounts 158.1 and 158.2)
  1. Report below the particulars (details) called for concerning allowances.
  2. Report all acquisitions of allowances at cost.
  3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts.
  4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k).
  5. Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
  6. Report on Line 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
  7. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts).
  8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies.
  9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
  10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Current Year Year One Year Two Year Three Future Years Totals
Line No.
NOx Allowances Inventory (Account 158.1)
(a)
No.
(b)
Amt.
(c)
No.
(d)
Amt.
(e)
No.
(f)
Amt.
(g)
No.
(h)
Amt.
(i)
No.
(j)
Amt.
(k)
No.
(l)
Amt.
(m)
1
Balance-Beginning of Year
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
5
Returned by EPA
6
7
8
Purchases/Transfers:
9
10
11
12
13
14
15
Total
16
17
Relinquished During Year:
18
Charges to Account 509
19
Other:
20
Allowances Used
21
Cost of Sales/Transfers:
22
23
24
25
26
27
28
Total
29
Balance-End of Year
30
31
Sales:
32
Net Sales Proceeds(Assoc. Co.)
33
Net Sales Proceeds (Other)
34
Gains
35
Losses
Allowances Withheld (Acct 158.2)
36
Balance-Beginning of Year
37
Add: Withheld by EPA
38
Deduct: Returned by EPA
39
Cost of Sales
40
Balance-End of Year
41
42
Sales
43
Net Sales Proceeds (Assoc. Co.)
44
Net Sales Proceeds (Other)
45
Gains
46
Losses


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
WRITTEN OFF DURING YEAR
Line No.
DescriptionOfExtraordinaryPropertyLoss
Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).]
(a)
ExtraordinaryPropertyLossesNotYetRecognized
Total Amount of Loss
(b)
ExtraordinaryPropertyLossesRecognized
Losses Recognized During Year
(c)
ExtraordinaryPropertyLossesWrittenOffAccountCharged
Account Charged
(d)
ExtraordinaryPropertyLossesWrittenOff
Amount
(e)
ExtraordinaryPropertyLosses
Balance at End of Year
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
20 TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
WRITTEN OFF DURING YEAR
Line No.
DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts
Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)]
(a)
UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized
Total Amount of Charges
(b)
UnrecoveredPlantAndRegulatoryStudyCostsRecognized
Costs Recognized During Year
(c)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged
Account Charged
(d)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff
Amount
(e)
UnrecoveredPlantAndRegulatoryStudyCosts
Balance at End of Year
(f)
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Transmission Service and Generation Interconnection Study Costs
  1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies.
  2. List each study separately.
  3. In column (a) provide the name of the study.
  4. In column (b) report the cost incurred to perform the study at the end of period.
  5. In column (c) report the account charged with the cost of the study.
  6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
  7. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.
DescriptionOfStudyPerformed
Description
(a)
StudyCostsIncurred
Costs Incurred During Period
(b)
StudyCostsAccountCharged
Account Charged
(c)
StudyCostsReimbursements
Reimbursements Received During the Period
(d)
StudyCostsAccountReimbursed
Account Credited With Reimbursement
(e)
1
Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Total
21
Generation Studies
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Total
40 Grand Total


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
OTHER REGULATORY ASSETS (Account 182.3)
  1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
  2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes.
  3. For Regulatory Assets being amortized, show period of amortization.
CREDITS
Line No.
DescriptionAndPurposeOfOtherRegulatoryAssets
Description and Purpose of Other Regulatory Assets
(a)
OtherRegulatoryAssets
Balance at Beginning of Current Quarter/Year
(b)
IncreaseDecreaseInOtherRegulatoryAssets
Debits
(c)
OtherRegulatoryAssetsWrittenOffAccountCharged
Written off During Quarter/Year Account Charged
(d)
OtherRegulatoryAssetsWrittenOffRecovered
Written off During the Period Amount
(e)
OtherRegulatoryAssets
Balance at end of Current Quarter/Year
(f)
1
Deferred Taxes Recoverable in Rates
933,140,071
202,534,339
133,396,552
1,002,277,858
2
Amortized Over Various Lives
3
Employer's Accounting for Post-
6,612,000
1,948,000
4,664,000
4
Employment Benefits
5
Environmental Clean-Up
18,970,953
462,056
1,663,584
17,769,425
6
Balancing Account Undercollections
1,066,520,210
235,633,543
12,015,191
1,290,138,562
7
Pension Benefits
68,654,459
68,570,865
83,594
8
SONGS Mitigation
36,931,880
7,288,911
44,220,791
9
Electric Derivatives
75,094,995
42,489,207
32,605,788
10
Contribution to City of Escondido
902,975
162,180
740,795
11
(20 year life, starting 2006)
12
Asset Retirement Obligations
23,319,537
5,822,739
2,882,097
26,260,179
13
Sunrise Wildfire Mitigation
121,485,983
770,193
122,256,176
14
Beyond The Meter
32,769,065
6,615,776
4,676,982
34,707,859
15
Theoretical Withdrawal Premium OIL
12,393,779
172,801
12,220,978
16
Post Retirement Benefits Other than
1,473,050
769,501
2,242,551
17
Pension
18
Worker's Compensation (Incurred
226,269
226,269
19
But Not Recorded)
20
2000 Energy Crisis Disbursement
1,866,070
1,866,070
44
TOTAL
2,398,495,226
461,763,128
267,977,459
2,592,280,895


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
  1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
  2. For any deferred debit being amortized, show period of amortization in column (a)
  3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
CREDITS
Line No.
Description of Miscellaneous Deferred Debits
(a)
Balance at Beginning of Year
(b)
Debits
(c)
Credits Account Charged
(d)
Credits Amount
(e)
Balance at End of Year
(f)
1
Debt Issuance costs
1,724,882
434,793
1,290,089
2
Southwest Powerlink Deferred
285,034
15,744
269,290
3
per CPUC
4
(amortization 01/1986 - 12/2023)
5
Mitigation Fund
137,706
9
137,697
6
Environmental Program
8,312,535
848,400
1,140,576
8,020,359
7
Workers Comp Receivable
11,459,213
1,894,099
9,565,114
8
SONGS Decommissioning
132,173
60,477
192,650
9
Pendleton Energy Park
195,734
195,734
10
Franchise Agreement
1,274,025
1,274,025
11
SONGS Reg Asset Receivable
11,586,157
11,586,157
12
PBOP Asset
20,085,874
10,616,874
9,469,000
13
Surplus Material
5,937,802
585,809
6,523,611
14
Airbus Helicopter Trade Account
462,000
462,000
15
Wildfire Fund AB1054
362,940,501
31,479,968
331,460,533
16
(amortization 07/2019-07/2034)
17
Line of credit (LOC) fees
2,491,173
747,352
1,743,821
18
Camp Pendleton Easement
517,000
517,000
19
Miscellaneous Other
88,321
5,031
35,416
57,936
20
Renewable Meter Adapter
106,206
106,206
47
Miscellaneous Work in Progress
48
Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49
TOTAL
426,356,105
371,285,065


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.
  2. At Other (Specify), include deferrals relating to other income and deductions.
Line No.
DescriptionOfAccumulatedDeferredIncomeTax
Description and Location
(a)
AccumulatedDeferredIncomeTaxes
Balance at Beginning of Year
(b)
AccumulatedDeferredIncomeTaxes
Balance at End of Year
(c)
1
Electric
2
Federal
(a)
66,270,343
(b)
74,502,660
3
State
33,293,445
39,622,432
7
Other
8
TOTAL Electric (Enter Total of lines 2 thru 7)
(c)
99,563,788
(d)
114,125,092
9
Gas
10
Federal
5,393,701
4,120,596
11
State
3,058,219
2,528,489
15
Other
16
TOTAL Gas (Enter Total of lines 10 thru 15)
8,451,920
6,649,085
17.1
Other (Specify)
410,776
410,795
17
Other (Specify)
18
TOTAL (Acct 190) (Total of lines 8, 16 and 17)
108,426,484
121,184,972
Notes


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes
Account 190 electric balance at the beginning of the year reflects amortization of transmission related excess deferred federal income taxes in the amount of $1,981,586.
(b) Concept: AccumulatedDeferredIncomeTaxes
Account 190 electric balance at the end of the year reflects amortization of transmission related excess deferred federal income taxes in the amount of $1,839,074.

The deferred tax asset related to FERC transmission on a stand-alone basis as of December 31, 2021, 2020, 2019, 2018 and 2017 is reflected in the table below:


STAND-ALONE FERC TRANSMISSION NET OPERATING LOSS DEFERRED TAX ASSET (1)
(Dollars in millions)
Years Ended December 31,
2021 2020 2019 2018 2017
FERC AC 190
FERC – Remeasured Amount $ 38  $ 57  $ 119  $ 124  $ 162 
FERC – Excess Reserve Protected 105  107  108  109  $ 108 
FERC – Excess Reserve Unprotected —  —  —  —  $ — 
Total $ 143  $ 164  $ 227  $ 233  $ 270 
(1) Does not include any amounts related to Citizens.
(c) Concept: AccumulatedDeferredIncomeTaxes
Account 190 non-Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the beginning of the year was ($164,013,239).

Account 190 Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the beginning of the year was ($8,452,524).

Account 190 transmission allocation related other deferred tax (asset) included in electric accumulated deferred income taxes at the beginning of the year was ($2,255,357).
(d) Concept: AccumulatedDeferredIncomeTaxes
Account 190 non-Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the end of the year was ($143,286,173).

Account 190 Citizen transmission related deferred tax (asset) included in electric accumulated deferred income taxes at the end of the year was ($7,384,342).

Account 190 transmission allocation related other deferred tax (asset) included in electric accumulated deferred income taxes at the end of the year was ($1,937,052).

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
CAPITAL STOCKS (Account 201 and 204)
  1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
  2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
  3. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued.
  4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative.
  5. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year.
  6. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.
Class and Series of Stock and Name of Stock Series
(a)
Number of Shares Authorized by Charter
(b)
Par or Stated Value per Share
(c)
Call Price at End of Year
(d)
Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares
(e)
Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount
(f)
Held by Respondent As Reacquired Stock (Acct 217) Shares
(g)
Held by Respondent As Reacquired Stock (Acct 217) Cost
(h)
Held by Respondent In Sinking and Other Funds Shares
(i)
Held by Respondent In Sinking and Other Funds Amount
(j)
1
Common Stock (Account 201)
2
Common
255,000,000
2.50
116,583,358
291,458,395
7
Total
255,000,000
116,583,358
291,458,395
8
Preferred Stock (Account 204)
9
Preferred Stock
45,000,000
11
Total
45,000,000
1
Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5
Total


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2022-04-15
Year/Period of Report

End of:
2021
/
Q4
Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change.
  1. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation.
  2. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related.
  3. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
  4. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.
Item
(a)
Amount
(b)
1
DonationsReceivedFromStockholdersAbstract
Donations Received from Stockholders (Account 208)
2
DonationsReceivedFromStockholders
Beginning Balance Amount
3.1
IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders
Increases (Decreases) from Sales of Donations Received from Stockholders
4
DonationsReceivedFromStockholders
Ending Balance Amount
5
ReductionInParOrStatedValueOfCapitalStockAbstract
Reduction in Par or Stated Value of Capital Stock (Account 209)
6
ReductionInParOrStatedValueOfCapitalStock
Beginning Balance Amount
7.1
IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock
Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8
ReductionInParOrStatedValueOfCapitalStock
Ending Balance Amount
9
GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract
Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10
GainOnResaleOrCancellationOfReacquiredCapitalStock
Beginning Balance Amount
11.1
IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock
Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12
GainOnResaleOrCancellationOfReacquiredCapitalStock
Ending Balance Amount
13
MiscellaneousPaidInCapitalAbstract
Miscellaneous Paid-In Capital (Account 211)
14
MiscellaneousPaidInCapital
Beginning Balance Amount
802,165,368
15.1
IncreasesDecreasesDueToMiscellaneousPaidInCapital
Increases (Decreases) Due to Miscellaneous Paid-In Capital
16
MiscellaneousPaidInCapital
Ending Balance Amount
802,165,368
17
OtherPaidInCapitalAbstract
Historical Data - Other Paid in Capital
18
OtherPaidInCapitalDetail
Beginning Balance Amount
19.1
IncreasesDecreasesInOtherPaidInCapital
Increases (Decreases) in Other Paid-In Capital
20
OtherPaidInCapitalDetail
Ending Balance Amount
40
OtherPaidInCapital
Total
802,165,368


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
CAPITAL STOCK EXPENSE (Account 214)
  1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
  2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.
NameOfClassAndSeriesOfStock
Class and Series of Stock
(a)
CapitalStockExpense
Balance at End of Year
(b)
1
Common
24,605,640
22
TOTAL
24,605,640


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
  1. Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt.
  2. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number.
  3. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received, and in column (b) include the related account number.
  4. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number.
  5. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates.
  6. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge.
  7. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote.
  8. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
  9. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.
ClassAndSeriesOfObligationCouponRateDescription
Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates)
(a)
RelatedAccountNumber
Related Account Number
(b)
Principal Amount of Debt Issued
(c)
LongTermDebtIssuanceExpensePremiumOrDiscount
Total Expense, Premium or Discount
(d)
LongTermDebtIssuanceExpenses
Total Expense
(e)
LongTermDebtPremium
Total Premium
(f)
LongTermDebtDiscount
Total Discount
(g)
NominalDateOfIssue
Nominal Date of Issue
(h)
DateOfMaturity
Date of Maturity
(i)
AmortizationPeriodStartDate
AMORTIZATION PERIOD Date From
(j)
AmortizationPeriodEndDate
AMORTIZATION PERIOD Date To
(k)
Outstanding (Total amount outstanding without reduction for amounts held by respondent)
(l)
Interest for Year Amount
(m)
1
Bonds (Account 221)
2
5.350% Series BBB due 2035
250,000,000
2,709,950
295,000
05/19/2005
05/15/2035
05/19/2005
05/15/2035
250,000,000
13,375,000
3
6.000% Series DDD due 2026
250,000,000
2,429,000
1,117,500
06/08/2006
06/01/2026
06/08/2006
06/01/2026
250,000,000
15,000,000
4
6.125% Series FFF due 2037
250,000,000
2,556,327
780,000
09/20/2007
09/15/2037
09/20/2007
09/15/2037
250,000,000
15,312,500
5
6.000% Series GGG due 2039
300,000,000
3,057,571
1,380,000
05/14/2009
06/01/2039
05/14/2009
06/01/2039
300,000,000
18,000,000
6
5.350% Series HHH due 2040
250,000,000
2,486,955
335,000
05/13/2010
05/15/2040
05/13/2010
05/15/2040
250,000,000
13,375,000
7
4.500% Series III due 2040
500,000,000
5,044,008
5,515,000
08/26/2010
08/15/2040
08/26/2010
08/15/2040
500,000,000
22,500,000
8
3.000% Series JJJ due 2021
350,000,000
2,775,568
1,795,500
08/18/2011
08/15/2021
08/18/2011
08/15/2021
6,475,000
9
3.950% Series LLL due 2041
250,000,000
2,639,787
350,000
11/17/2011
11/15/2041
11/17/2011
11/15/2041
250,000,000
9,875,000
10
4.300% Series MMM due 2042
250,000,000
2,569,738
1,297,500
03/22/2012
04/01/2042
03/22/2012
04/01/2042
250,000,000
10,750,000
11
3.600% Series NNN due 2023
450,000,000
3,670,004
72,000
09/09/2013
09/01/2023
09/09/2013
09/01/2023
450,000,000
16,200,000
12
1.914% Series PPP due 2022
250,000,000
1,568,025
03/12/2015
02/01/2022
03/12/2015
02/01/2022
17,859,000
569,677
13
2.500% Series QQQ due 2026
500,000,000
4,279,086
1,625,000
05/19/2016
05/15/2026
05/19/2016
05/15/2026
500,000,000
12,500,000
14
3.750% Series RRR due 2047
400,000,000
4,038,478
1,784,000
06/08/2017
06/01/2047
06/08/2017
06/01/2047
400,000,000
15,000,000
15
4.150% Series SSS due 2048
400,000,000
4,072,043
1,768,000
05/17/2018
05/15/2048
05/17/2018
05/15/2048
400,000,000
16,600,000
16
4.100% Series TTT due 2049
400,000,000
4,345,931
420,000
05/31/2019
06/15/2049
05/31/2019
06/15/2049
400,000,000
16,400,000
17
3.320% Series UUU due 2050
400,000,000
4,464,828
532,000
04/07/2020
04/15/2050
04/07/2020
04/15/2050
400,000,000
13,280,000
18
1.700% Series VVV due 2030
800,000,000
6,688,168
1,392,000
09/28/2020
10/01/2030
09/28/2020
10/01/2030
800,000,000
13,600,000
19
2.950% Series WWW due 2051 (D.08-07-029, D.18-02-012, D.20-04-015 issued August 13, 2021)
750,000,000
8,236,055
4,740,000
08/13/2021
08/15/2051
08/13/2021
08/15/2051
750,000,000
8,481,250
20
Subtotal
(a)
7,000,000,000
(b)
67,631,522
25,198,500
6,417,859,000
237,293,427
21
Reacquired Bonds (Account 222)
22
23
24
25
Subtotal
26
Advances from Associated Companies (Account 223)
27
28
29
30
Subtotal
31
Other Long Term Debt (Account 224)
32
33
34
35
Subtotal
33 TOTAL
7,000,000,000
6,417,859,000
237,293,427


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: BondsPrincipalAmountIssued
D.93-09-069 - At December 2021 total remaining authority for new preferred debt under this decision was $48,360,000.

D.04-01-009 - At December 2021 total remaining authority for new preferred debt under this decision was $4,000,000 and $76,000,000 for rollover preferred.

D.06-05-015 - At December 2021 total remaining authority for new preferred debt under this decision was $200,000,000.

D.08-07-029 - In July 2008, SDG&E received authority from the California Public Utilities Commission to issue $687,000,000 of new debt and $413,000,000 in rollover debt. In August 2021, SDG&E issued 2.9500% First Mortgage bond series WWW for $123,130,000 due 2051. At December 2021 there was no remaining authority.

D.10-10-023 - At December 2021 total remaining authority for new preferred debt under this decision was $150,000,000.

D.18-02-012 - In February 2018, SDG&E received authority from the California Public Utilities Commission to issue $750,000,000 of new debt and $300,000,000 in rollover debt. In August 2021, SDG&E issued 2.9500% First Mortgage bond series WWW for $226,870,000 due 2051. At December 2021 total remaining authority for rollover debt under this decision was $73,130,000.

D.20-04-015 - In April 2020, SDG&E received authority from the California Public Utilities Commission to issue $2,300,000,000 of new debt and $730,000,000 in rollover debt. In August 2021, SDG&E issued 2.9500% First Mortgage bond series WWW for $400,000,000 due 2051. At December 2021 total remaining authority under this decision was $1,115,430,000 for new debt, $803,130,000 for rollover debt, $402,360,000 for new preferred and $76,000,000 for rollover referred.
(b) Concept: BondIssuanceExpense
Expense $ 67,631,522 
Discount $ 25,198,500 
Account 221 $ 92,830,022 

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
  1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
  2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
  3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.
Particulars (Details)
(a)
Amount
(b)
1
Net Income for the Year (Page 117)
(a)
819,252,902
2
Reconciling Items for the Year
3
4
Taxable Income Not Reported on Books
5
Contributions in Aid of Construction
45,504,230
6
Other (Itemized within footnote)
(b)
4,454
9
Deductions Recorded on Books Not Deducted for Return
10
Book Depreciation on Fixed Assets
868,811,119
11
Federal and State Taxes
200,774,455
12
Amortization and Interest Capitalized
80,195,522
13
Other (Itemized within footnote)
(c)
21,810,068
14
Income Recorded on Books Not Included in Return
15
Allowance for Funds Used During Construction
105,742,795
16
Unbilled Revenue
14,025,186
17
Restricted Stock
18
Other (Itemized within footnote)
(d)
18,268,289
19
Deductions on Return Not Charged Against Book Income
20
Tax Depreciation on Fixed Assets
676,357,985
21
Regulatory Balancing Accounts
333,502,904
22
Elec & Gas Repairs
246,883,137
23
Software Development Costs
196,307,485
24
Removal Costs
98,601,896
25
Current State Tax Deduction
34,571,461
26
Other (Itemized within footnote)
(e)
34,486,354
27
Federal Tax Net Income
277,605,255
28
Show Computation of Tax:
29
Federal Tax @ 21%
58,297,104
30
Deferred Taxes
82,998,127
31
Tax Credits and Other Adjustments (net)
18,686,454
32
Fed Discrete Taxes
11,084,658
33
Total Federal Income Tax Expense
133,693,435


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: NetIncomeLoss
South Georgia Adjustment of $1,304,099 is included in book taxable income to reverse tax benefits flowed through in rates prior to full normalization of book/tax adjustments.
(b) Concept: TaxableIncomeNotReportedOnBooks
Fuel Tax Credit Addback $ 4,454 
$ 4,454 
(c) Concept: DeductionsRecordedOnBooksNotDeductedForReturn
Contingency Book Reserves $ 9,495,458 
Accrued Vacation 7,226,744 
Lobbying 970,582 
Miscellaneous Expenses 4,117,284 
$ 21,810,068 
(d) Concept: IncomeRecordedOnBooksNotIncludedInReturn
Keyman Life Insurance $ (7,593,458)
Deferred Construction Revenue (7,167,913)
Restricted Stock (1,625,688)
SONGS Decommissioning Costs (1,364,236)
Book Gain on Sale of Utility Property (516,994)
$ (18,268,289)
(e) Concept: DeductionsOnReturnNotChargedAgainstBookIncome
Abandonment Loss $ (13,759,744)
CARES Act Payroll tax deferral (10,866,733)
Bad Debt (7,291,263)
Property Taxes (1,770,135)
Deferred Debits/Credits (575,263)
Miscellaneous Inc/(Ded) (223,216)
$ (34,486,354)

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
  1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts.
  2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes.
  3. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts.
  4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
  5. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d).
  6. Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses.
  7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority.
  8. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts.
  9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT BEGINNING OF YEAR BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED
Line No.
DescriptionOfTaxesAccruedPrepaidAndCharged
Kind of Tax (See Instruction 5)
(a)
TypeOfTax
Type of Tax
(b)
TaxJurisdiction
State
(c)
TaxYear
Tax Year
(d)
TaxesAccrued
Taxes Accrued (Account 236)
(e)
PrepaidTaxes
Prepaid Taxes (Include in Account 165)
(f)
TaxesCharged
Taxes Charged During Year
(g)
TaxesPaid
Taxes Paid During Year
(h)
TaxAdjustments
Adjustments
(i)
TaxesAccrued
Taxes Accrued (Account 236)
(j)
PrepaidTaxes
Prepaid Taxes (Included in Account 165)
(k)
TaxesAccruedPrepaidAndCharged
Electric (Account 408.1, 409.1)
(l)
IncomeTaxesExtraordinaryItems
Extraordinary Items (Account 409.3)
(m)
AdjustmentsToRetainedEarnings
Adjustment to Ret. Earnings (Account 439)
(n)
TaxesIncurredOther
Other
(o)
1
Taxes on Income (Note 3)
Federal Tax
CA
2021
3,501,695
34,763,477
46,057,044
6,171,192
0
1,620,680
53,377,736
18,614,259
2
Retirement (Note 4)
Federal Tax
CA
2021
10,758,243
0
33,414,426
34,920,837
9,251,832
0
(e)
12,453,808
(g)
20,960,618
3
Unemployment (Note 4)
Federal Tax
CA
2021
42,425
0
183,992
219,687
6,730
0
137,011
46,981
4
Medicare (Note 4)
Federal Tax
CA
2021
110,376
0
10,180,546
10,128,813
162,109
0
3,794,362
6,386,184
5
Fuel Tax
Federal Tax
CA
2021
0
95,743
561,274
575,769
0
110,238
561,274
6
Subtotal Federal Tax
14,412,739
(b)
95,743
79,103,715
91,902,150
(d)
6,171,192
9,420,671
1,730,918
(f)
69,762,917
9,340,798
7
Franchise (Note 3)
State Tax
CA
2021
0
(c)
495,861
12,874,523
20,734,748
2,645,637
0
5,710,449
22,323,632
9,449,109
8
Unemployment (Note 4)
State Tax
CA
2021
148,509
0
528,564
658,410
18,663
0
393,599
134,965
9
Sales and Use (Note 2)
State Tax
CA
2021
14,485
0
1,440,174
1,116,892
337,767
0
1,440,174
10
Fuel Tax
State Tax
CA
2021
7,400
0
16,480
23,880
0
0
16,480
11
Subtotal State Tax
170,394
495,861
14,859,741
22,533,930
2,645,637
356,430
5,710,449
22,717,231
7,857,490
12
Ad Valorem (Note 1)
Local Tax
CA
2021
0
840,997
183,585,501
204,392,592
20,806,949
0
841,139
158,074,376
25,511,125
13
Sales and Use (Note 2)
Local Tax
CA
2021
12,232
0
420,052
325,760
106,524
0
420,052
14
Business License
Local Tax
CA
2021
0
0
68,282
68,282
0
0
63,080
5,202
15
Subtotal Local Tax
12,232
840,997
184,073,835
204,786,634
20,806,949
106,524
841,139
158,137,456
25,936,379
16
0
0
0
0
17
Subtotal Other Tax
0
0
0
0
18
Subtotal Property Tax
0
0
0
0
19
Subtotal Real Estate Tax
0
0
0
0
20
Subtotal Unemployment Tax
0
0
0
0
21
Subtotal Sales And Use Tax
0
0
0
0
22
Subtotal Income Tax
0
0
0
0
0
23
Subtotal Excise Tax
0
0
0
0
24
Subtotal Fuel Tax
0
0
0
0
25
Subtotal Federal Insurance Tax
0
0
0
0
26
Subtotal Franchise Tax
0
0
0
0
27
Subtotal Miscellaneous Other Tax
0
0
0
0
28
Subtotal Other Federal Tax
0
0
0
0
29
Subtotal Other State Tax
0
0
0
0
30
Subtotal Other Property Tax
0
0
0
0
31
Subtotal Other Use Tax
0
0
0
0
32
Subtotal Other Advalorem Tax
0
0
0
0
33
Subtotal Other License And Fees Tax
0
0
0
0
34
Subtotal Payroll Tax
0
0
0
0
35
Subtotal Advalorem Tax
0
0
0
0
36
Subtotal Other Allocated Tax
0
0
0
0
37
Subtotal Severance Tax
0
0
0
0
38
Subtotal Penalty Tax
0
0
0
0
39
Subtotal Other Taxes And Fees
0
0
0
0
40
TOTAL
(h)
14,595,365
1,432,601
278,037,291
319,222,714
29,623,778
9,883,625
8,282,506
250,617,604
27,419,687


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: PrepaidTaxes
Description Adjustment
Amount
FERC
190
FERC
283
FERC
171
FERC
237
Utilization of Net Operating Loss
Balance Sheet Reclassification Due to FIN 48 Liabilities (6,171,186) 6,171,186 
Balance Sheet Reclassification Due to FIN 48 Liabilities - Interest
Total - Federal Income Tax Adjustment (6,171,186) —  6,171,186  —  — 
(b) Concept: PrepaidTaxes
This adjustment is for a portion of property taxes paid on construction work in progress. The property tax charged during the year was reduced and capitalized to certain assets under construction.
(c) Concept: PrepaidTaxes
Description Adjustment
Amount
FERC
190
FERC
283
FERC
171
FERC
237
Balance Sheet Reclassification Due to FIN 48 Liabilities (2,645,634) 2,645,634 
Total - California Corporation Franchise Tax Adjustment (2,645,634) 2,645,634  —  —  — 
(d) Concept: TaxAdjustments
Property tax expense of $632,254 and $67,128 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines are deducted and moved to column (l).
(e) Concept: TaxesAccruedPrepaidAndCharged
Payroll tax expense of $21,778 and $2,438 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines are deducted and moved to column (l).
(f) Concept: TaxesAccruedPrepaidAndCharged
Includes property tax expense of $632,254 and $67,128 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines.
(g) Concept: TaxesIncurredOther
Includes payroll tax expense of $21,778 and $2,438 associated with the Citizens portion of the Border-East and SX-PQ Segment B lines.
(h) Concept: TaxesAccrued
Note 1:
Ad Valorem taxes are allocated based on type of assets in each taxing jurisdiction.

Note 2:
Sales and Use taxes are allocated based on the Common Allocation Factor.

Sales and Use tax adjustments in column "f" are to adjust carry forward balances from last year.

Note 3:
State and Franchise Tax and Federal Income Tax are charged to departments based on total taxable income generated by each department.

Note 4:
Retirement, Unemployment, and Medicare taxes are charged to departments as a percentage of total taxable labor charged.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)

Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average period over which the tax credits are amortized.

Deferred for Year Allocations to Current Year's Income
Line No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Account No.
(c)
Amount
(d)
Account No.
(e)
Amount
(f)
Adjustments
(g)
Balance at End of Year
(h)
Average Period of Allocation to Income
(i)
ADJUSTMENT EXPLANATION
(j)
1
Electric Utility
2
3%
3
4%
4
7%
5
10%
6
Various
13,377,869
271,798
13,106,071
25 to 30 years
8
TOTAL Electric (Enter Total of lines 2 thru 7)
13,377,869
(a)
271,798
13,106,071
9
Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10
`
11
Gas Utility Various
25 to 30 years
47 OTHER TOTAL
48 GRAND TOTAL
13,377,869
13,106,071


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredInvestmentTaxCreditsAllocationToIncomeAmount
Account 255 transmission related amortization of investment tax credits allocated to current year income is $264,763.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
OTHER DEFERRED CREDITS (Account 253)
  1. Report below the particulars (details) called for concerning other deferred credits.
  2. For any deferred credit being amortized, show the period of amortization.
  3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
DEBITS
Line No.
Description and Other Deferred Credits
(a)
Balance at Beginning of Year
(b)
Contra Account
(c)
Amount
(d)
Credits
(e)
Balance at End of Year
(f)
1
CIAC/CAC Tax Gross-Ups
68,553,578
12,521,108
13,656,407
69,688,877
2
Amortized over various 31 yr lives
3
SONGS Mitigation
35,704,361
858,869
8,208,288
43,053,780
4
OIL Insurance Limited
12,393,778
172,801
12,220,977
5
Sunrise Fire Mitigation Liability
117,840,601
3,718,291
4,415,575
118,537,885
6
Citizens Lease
83,292,528
3,736,060
79,556,468
7
Greenhouse Gas Obligations
26,730,880
57,693,422
30,962,542
8
Miscellaneous
38,768,619
34,186,934
22,076,370
26,658,055
9
Wildfire Fund Obligations
74,889,108
12,900,000
1,926,360
63,915,468
47
TOTAL
431,442,573
94,824,943
107,976,422
444,594,052


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report


End of:
2021
/
Q4
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1
Accelerated Amortization (Account 281)
2
Electric
3
Defense Facilities
4
Pollution Control Facilities
5
Other
5.1
Other (provide details in footnote):
8
TOTAL Electric (Enter Total of lines 3 thru 7)
9
Gas
10
Defense Facilities
11
Pollution Control Facilities
12
Other
12.1
Other (provide details in footnote):
15
TOTAL Gas (Enter Total of lines 10 thru 14)
16
Other
16.1
Other
16.2
Other
17
TOTAL (Acct 281) (Total of 8, 15 and 16)
18
Classification of TOTAL
19
Federal Income Tax
20
State Income Tax
21
Local Income Tax


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1 Account 282
2
Electric
(a)
1,577,151,826
97,001,290
71,673,287
Various
46,837,720
Various
84,390,108
1,640,032,217
3
Gas
172,724,264
11,827,148
9,360,846
Various
6,257,770
Various
20,487,745
(b)
189,420,541
4
Other (Specify)
0
5
Total (Total of lines 2 thru 4)
1,749,876,090
108,828,438
81,034,133
53,095,490
104,877,853
1,829,452,758
6
0
7
Non Utility
85,090,237
7,245,127
450,732
22,796,247
114,680,879
9
TOTAL Account 282 (Total of Lines 5 thru 8)
1,834,966,327
108,828,438
81,034,133
7,245,127
450,732
53,095,490
127,674,100
1,944,133,637
10
Classification of TOTAL
11
Federal Income Tax
1,483,061,519
80,655,424
68,891,083
5,098,782
450,732
36,986,634
90,055,564
1,552,542,840
12
State Income Tax
351,904,808
28,173,016
12,143,048
2,146,345
16,108,856
37,618,532
391,590,797
13
Local Income Tax
0


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOtherProperty
Account 282 electric balance at the beginning of the year reflects a reduction for (amortization) of non-Citizens transmission related excess deferred federal income taxes in the amount of ($4,309,561).

Account 282 electric balance at the beginning of the year reflects a reduction for (amortization) of Citizens transmission related excess deferred federal income taxes in the amount of ($180,826).

Account 282 non-Citizen transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the beginning of the year was $732,250,020.

Account 282 Citizen transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the beginning of the year was $12,022,715.

Account 282 Citizens SX-PQ transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the beginning of the year was $3,028,935.

Account 282 non-Citizen transmission related excess deferred income tax reserve at the beginning of the year was $376,621,256.

Account 282 Citizen transmission related excess deferred income tax reserve at the beginning of the year was $8,318,012.
(b) Concept: AccumulatedDeferredIncomeTaxesOtherProperty
Account 282 electric balance at the end of the year reflects a reduction for (amortization) of non-Citizens transmission related excess deferred federal income taxes in the amount of ($4,530,851).

Account 282 electric balance at the end of the year reflects a reduction for (amortization) of Citizens transmission related excess deferred federal income taxes in the amount of ($180,826).

Account 282 non-Citizen transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the end of the year was $771,220,222.

Account 282 Citizens Sunrise transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the end of the year was $11,512,111.

Account 282 Citizens SX-PQ transmission related accumulated deferred income taxes included in electric accumulated deferred income taxes at the end of the year was $3,145,258.

Account 282 non-Citizen transmission related excess deferred income tax reserve at the end of the year was $358,966,142.

Account 282 Citizen transmission related excess deferred income tax reserve at the end of the year was $8,137,186.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
  1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other.
  4. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1 Account 283
2
Electric
3
Electric
(a)
223,721,394
175,029,998
70,885,223
57,610,964
79,014,069
(b)
349,269,274
4
0
0
9 TOTAL Electric (Total of lines 3 thru 8)
223,721,394
175,029,998
70,885,223
57,610,964
79,014,069
349,269,274
10
Gas
11
Gas
28,049,918
13,149,204
1,331,771
14,162,251
17,305,845
45,674,487
12
0
0
17 TOTAL Gas (Total of lines 11 thru 16)
28,049,918
13,149,204
1,331,771
14,162,251
17,305,845
45,674,487
18 TOTAL Other
38,360,292
23,672
380,514
314,591
9,178,369
46,867,228
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
290,131,604
188,179,202
69,553,452
23,672
380,514
72,087,806
105,498,283
441,810,989
20
Classification of TOTAL
21
Federal Income Tax
198,737,105
133,501,998
52,350,041
23,672
267,788
49,903,217
72,171,446
301,913,175
22
State Income Tax
91,394,499
54,677,204
17,203,411
112,726
22,184,589
33,326,837
139,897,814
23
Local Income Tax
0
NOTES


FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther
Account 283 transmission allocation related other deferred tax liability included in electric accumulated deferred income taxes at the beginning of the year was $7,906,429.
(b) Concept: AccumulatedDeferredIncomeTaxesOther
Account 283 transmission allocation related other deferred tax liability included in electric accumulated deferred income taxes at the end of the year was $7,891,472.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
OTHER REGULATORY LIABILITIES (Account 254)
  1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
  2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes.
  3. For Regulatory Liabilities being amortized, show period of amortization.
DEBITS
Line No.
Description and Purpose of Other Regulatory Liabilities
(a)
Balance at Beginning of Current Quarter/Year
(b)
Account Credited
(c)
Amount
(d)
Credits
(e)
Balance at End of Current Quarter/Year
(f)
1
Deferred Taxes Payable in rates
911,640,379
36,742,482
2,351,268
877,249,165
2
Asset Retirement Obligations
548,154,797
14,383,252
15,604,908
549,376,453
3
Balancing Account Overcollections
749,561,463
108,188,429
9,531,930
650,904,964
4
Electric / Gas Derivatives
128,289,761
45,586,393
70,033
82,773,401
5
PBOP Benefits
20,085,874
10,616,874
9,469,000
41 TOTAL
2,357,732,274
215,517,430
27,558,139
2,169,772,983


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Electric Operating Revenues
  1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages.
  2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
  3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers means the average of twelve figures at the close of each month.
  4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
  5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
  6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.)
  7. See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases.
  8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
  9. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.
Title of Account
(a)
Operating Revenues Year to Date Quarterly/Annual
(b)
Operating Revenues Previous year (no Quarterly)
(c)
MEGAWATT HOURS SOLD Year to Date Quarterly/Annual
(d)
MEGAWATT HOURS SOLD Amount Previous year (no Quarterly)
(e)
AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly)
(f)
AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly)
(g)
1
SalesOfElectricityHeadingAbstract
Sales of Electricity
2
ResidentialSalesAbstract
(440) Residential Sales
1,646,785,175
1,600,890,105
5,671,599
6,606,155
1,277,154
1,311,290
3
CommercialAndIndustrialSalesAbstract
(442) Commercial and Industrial Sales
4
CommercialSalesAbstract
Small (or Comm.) (See Instr. 4)
1,051,760,623
1,402,837,991
4,177,710
5,872,843
108,715
151,058
5
IndustrialSalesAbstract
Large (or Ind.) (See Instr. 4)
266,665,956
358,553,421
1,397,952
1,841,889
253
392
6
PublicStreetAndHighwayLightingAbstract
(444) Public Street and Highway Lighting
11,386,964
14,272,909
51,239
77,228
1,651
2,090
7
OtherSalesToPublicAuthoritiesAbstract
(445) Other Sales to Public Authorities
8
SalesToRailroadsAndRailwaysAbstract
(446) Sales to Railroads and Railways
9
InterdepartmentalSalesAbstract
(448) Interdepartmental Sales
10
SalesToUltimateConsumersAbstract
TOTAL Sales to Ultimate Consumers
2,976,598,718
3,376,554,426
11,298,500
14,398,115
1,387,773
1,464,830
11
SalesForResaleAbstract
(447) Sales for Resale
559,623,423
414,730,041
9,195,146
10,344,942
12
SalesOfElectricityAbstract
TOTAL Sales of Electricity
3,536,222,141
3,791,284,467
20,493,646
24,743,057
1,387,773
1,464,830
13
ProvisionForRateRefundsAbstract
(Less) (449.1) Provision for Rate Refunds
14
RevenuesNetOfProvisionForRefundsAbstract
TOTAL Revenues Before Prov. for Refunds
3,536,222,141
3,791,284,467
20,493,646
24,743,057
1,387,773
1,464,830
15
OtherOperatingRevenuesAbstract
Other Operating Revenues
16
ForfeitedDiscounts
(450) Forfeited Discounts
17
MiscellaneousServiceRevenues
(451) Miscellaneous Service Revenues
(a)
94,041,045
(d)
100,035,626
18
SalesOfWaterAndWaterPower
(453) Sales of Water and Water Power
19
RentFromElectricProperty
(454) Rent from Electric Property
(b)
4,820,177
(e)
3,551,962
20
InterdepartmentalRents
(455) Interdepartmental Rents
21
OtherElectricRevenue
(456) Other Electric Revenues
(c)
1,261,094,462
(f)
849,991,545
22
RevenuesFromTransmissionOfElectricityOfOthers
(456.1) Revenues from Transmission of Electricity of Others
316,575,181
271,027,123
23
RegionalTransmissionServiceRevenues
(457.1) Regional Control Service Revenues
24
MiscellaneousRevenue
(457.2) Miscellaneous Revenues
25
OtherMiscellaneousOperatingRevenues
Other Miscellaneous Operating Revenues
26
OtherOperatingRevenues
TOTAL Other Operating Revenues
1,676,530,865
1,224,606,256
27
ElectricOperatingRevenues
TOTAL Electric Operating Revenues
5,212,753,006
5,015,890,723
Line12, column (b) includes $
of unbilled revenues.
Line12, column (d) includes
MWH relating to unbilled revenues


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues
Description
San Diego Franchise Fee Surcharge $ 87,362,890 
Net Energy Metering 3,609,268 
Service Establishment 2,020,918 
Mover Service Charge 547,298 
Late Payment Charge (443)
Other* 501,114 
$ 94,041,045 
*    Individual balances are less than $250,000
(b) Concept: RentFromElectricProperty
Includes Transmission Revenue Credits of $447,000
(c) Concept: OtherElectricRevenue
Description
Direct Access $ 352,834,389 
Cap and Trade Revenues 161,825,842 
Balancing Accounts 208,448,901 
CCA T&D Revenue 399,836,861 
Federal Project Management 7,649,899 
PUC Reimbursement Fee 22,235,549 
CIAC Income Tax 5,895,373 
LCFS Rec Credits 16,268,835 
Shared Assets 7,215,238 
Generation Trans. Interconnection Rev. 2,549,526 
Unbilled Revenue 81,541,342 
Litigation (3,500,000)
Government Turnkey (6,666,264)
Employee Transfer Fees 538,749 
Joint Pole Activity 2,906,109 
Other* 1,514,113 
$ 1,261,094,462 
*    Individual balances are less than $250,000
*    Includes Transmission Revenue Credits of $4,418,332
(d) Concept: MiscellaneousServiceRevenues
Description
San Diego Franchise Fee Surcharge $ 91,351,964 
Service Establishment 4,059,306 
Net Energy Metering 2,809,830 
Late Payment Charge 1,181,049 
Mover Service Charge 150,041 
Other* 483,436 
$ 100,035,626 
*    Individual balances are less than $250,000
(e) Concept: RentFromElectricProperty
Includes Transmission Revenue Credits of $208,760
(f) Concept: OtherElectricRevenue
Description
Direct Access $ 287,858,282 
Cap and Trade Revenues 105,107,923 
Balancing Accounts 385,160,293 
CCA T&D Revenue 11,281,401 
Federal Project Management 17,175,228 
CIAC Income Tax 6,006,110 
LCFS Rec Credits 24,346,377 
Shared Assets 3,802,823 
PUC Reimbursement Fee 13,015,817 
Government Turnkey (16,044,837)
Unbilled Revenue 4,565,763 
Joint Pole Activity 3,589,710 
Generation Trans. Interconnection Rev. 2,587,281 
Employee Transfer Fees 567,500 
Other* 971,874 
$ 849,991,545 
*    Individual balances are less than $250,000
*    Includes Transmission Revenue Credits of $3,501,419

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
  1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.
Description of Service
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
DR
1,303,978
351,838,087
296,860
4,393
0.2698
2
DRTOU
4,016,918
1,208,300,242
951,343
4,222
0.3008
3
EVTOU
181,006
43,852,622
22,331
8,106
0.2423
4
DRLI
5
DM
36,989
11,167,368
3,730
9,917
0.3019
6
DS
16,051
4,106,408
218
73,628
0.2558
7
DT
110,138
25,243,453
367
300,104
0.2292
8
OL-1
6,346
2,178,961
2,272
2,793
0.3434
9
DWL
173
98,034
33
5,242
0.5667
41 TOTAL Billed Residential Sales
5,671,599
1,646,785,175
1,277,154
4,441
0.2904
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL
5,671,599
1,646,785,175
1,277,154
4,441
0.2904


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
A
41,171
8,078,333
4,560
9,029
0.1962
2
ASTOD
355,168
78,928,703
28,920
12,281
0.2222
3
ATOU
76,685
16,910,755
1,495
51,294
0.2205
4
AD
5
UM
13,590
3,744,527
79
172,025
0.2755
6
PA
7
PAT1
272,365
51,805,082
4,603
59,171
0.1902
8
AL-TOU
2,252,922
606,648,936
9,487
237,475
0.2693
9
SPSS
1
10
DG
192,671
23,979,631
462
11
OL-1
1,107
364,219
397
2,788
0.3290
12
OLTOU
1,383
319,755
27
51,222
0.2312
13
TOUA
970,648
260,980,682
58,684
16,540
0.2689
41 TOTAL Billed Small or Commercial
4,177,710
1,051,760,623
108,715
38,428
0.2518
42 TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)
43 TOTAL Small or Commercial
4,177,710
1,051,760,623
108,715
38,428
0.2518


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
DG
134,480
5,774,052
19
7,077,895
0.0429
2
AL-TOU
1,205,038
243,875,222
221
5,452,661
0.2024
3
A6-TOU
58,434
17,016,682
13
4,494,923
0.2912
41 TOTAL Billed Large (or Ind.) Sales
1,397,952
266,665,956
253
5,525,502
0.1908
42 TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)
43 TOTAL Large (or Ind.)
1,397,952
266,665,956
253
5,525,502
0.1908


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed Commercial and Industrial Sales
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
LS1
13,555
4,957,799
630
21,516
0.3658
2
LS2
36,925
6,305,434
872
42,345
0.1708
3
LS3
759
123,731
149
5,094
0.1630
41 TOTAL Billed Public Street and Highway Lighting
51,239
11,386,964
1,651
31,035
0.2222
42 TOTAL Unbilled Rev. (See Instr. 6)
43 TOTAL
51,239
11,386,964
1,651
31,035
0.2222


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Page 310.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
41 TOTAL Billed - All Accounts
11,298,500
2,976,598,718
1,387,773
8,141
0.2635
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts
43 TOTAL - All Accounts
11,298,500
2,976,598,718
1,387,773
8,141
0.2635


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SALES FOR RESALE (Account 447)
  1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326).
  2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser.
  3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

    RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers.

    LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract.

    IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years.

    SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less.

    LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit.

    IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.

    OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote.

    AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment.

  4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k).
  5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided.
  6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
  7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
  8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser.
  9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24.
  10. Footnote entries as required and provide explanations following all required data.
ACTUAL DEMAND (MW) REVENUE
Line No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
FERC Rate Schedule or Tariff Number
(c)
Average Monthly Billing Demand (MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
Megawatt Hours Sold
(g)
Demand Charges ($)
(h)
Energy Charges ($)
(i)
Other Charges ($)
(j)
Total ($) (h+i+j)
(k)
1
California ISO
9,136,196
501,451,464
501,451,464
2
City of Escondido (Rincon Hydro Plant)
90
17,505
17,505
3
Calpine Energy Services LP
0
67,499
67,499
4
City of Burbank
2,400
138,800
138,800
5
City of Glendale Water and Power
800
21,600
21,600
6
City of Lancaster
0
3,375,135
3,375,135
7
City of San Jose
0
3,149,216
3,149,216
8
Clean Energy Alliance
0
7,674,362
7,674,362
9
Direct Energy Business Marketing
20,837
332,142
(a)
332,142
10
EDF Trading North America LLC
0
2,598,505
2,598,505
11
Exelon Generation Company LLC
0
6,626,084
(b)
2,308,304
8,934,388
12
Los Angeles Dept. of Water & Power
5,600
435,680
435,680
13
Pacific Gas & Electric Company
0
1,551,208
1,551,208
14
Peninsula Clean Energy Authority
19,000
264,100
(c)
264,100
15
Pioneer Community Energy
0
1,500,090
1,500,090
16
Portland General Electric
400
17,600
17,600
17
Powerex Corporation
3,200
112,000
112,000
18
Recurrent Energy Development
0
120,000
120,000
19
Sacramento Municipal Utility District
5,423
81,345
(d)
81,345
20
San Diego Community Power
0
16,159,620
16,159,620
21
Silicon Valley Clean Energy Authority
0
1,891,149
1,891,149
22
Sonoma Clean Power Authority
0
1,723,101
1,723,101
23
Southern California Edison
800
8,454,501
88,000
8,542,501
24
TransAlta Energy Marketing US
400
142,000
142,000
15
Subtotal - RQ
16
Subtotal-Non-RQ
9,195,146
54,890,470
501,747,062
2,985,891
559,623,423
17 Total
9,195,146
54,890,470
501,747,062
2,985,891
559,623,423


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: OtherChargesRevenueSalesForResale
Contract to sell Renewable Energy Credits
(b) Concept: OtherChargesRevenueSalesForResale
Contract to sell Renewable Energy Credits
(c) Concept: OtherChargesRevenueSalesForResale
Contract to sell Renewable Energy Credits
(d) Concept: OtherChargesRevenueSalesForResale
Contract to sell Renewable Energy Credits

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES

If the amount for previous year is not derived from previously reported figures, explain in footnote.

Line No.
Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
1
PowerProductionExpensesAbstract
1. POWER PRODUCTION EXPENSES
2
SteamPowerGenerationAbstract
A. Steam Power Generation
3
SteamPowerGenerationOperationAbstract
Operation
4
OperationSupervisionAndEngineeringSteamPowerGeneration
(500) Operation Supervision and Engineering
1,945,733
2,071,055
5
FuelSteamPowerGeneration
(501) Fuel
140,396,456
85,839,459
6
SteamExpensesSteamPowerGeneration
(502) Steam Expenses
102
7
SteamFromOtherSources
(503) Steam from Other Sources
8
SteamTransferredCredit
(Less) (504) Steam Transferred-Cr.
934
9
ElectricExpensesSteamPowerGeneration
(505) Electric Expenses
1,017,715
357,033
10
MiscellaneousSteamPowerExpenses
(506) Miscellaneous Steam Power Expenses
6,536,502
6,566,199
11
RentsSteamPowerGeneration
(507) Rents
35,143
35,143
12
Allowances
(509) Allowances
13
SteamPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 4 thru 12)
149,932,585
94,868,889
14
SteamPowerGenerationMaintenanceAbstract
Maintenance
15
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
(510) Maintenance Supervision and Engineering
588
16
MaintenanceOfStructuresSteamPowerGeneration
(511) Maintenance of Structures
183,550
103,659
17
MaintenanceOfBoilerPlantSteamPowerGeneration
(512) Maintenance of Boiler Plant
2,369,531
2,359,936
18
MaintenanceOfElectricPlantSteamPowerGeneration
(513) Maintenance of Electric Plant
582,672
352,104
19
MaintenanceOfMiscellaneousSteamPlant
(514) Maintenance of Miscellaneous Steam Plant
7,598,822
4,795,725
20
SteamPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 15 thru 19)
10,734,575
7,612,012
21
PowerProductionExpensesSteamPower
TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)
160,667,160
102,480,901
22
NuclearPowerGenerationAbstract
B. Nuclear Power Generation
23
NuclearPowerGenerationOperationAbstract
Operation
24
OperationSupervisionAndEngineeringNuclearPowerGeneration
(517) Operation Supervision and Engineering
9,300
25
NuclearFuelExpense
(518) Fuel
26
CoolantsAndWater
(519) Coolants and Water
27
SteamExpensesNuclearPowerGeneration
(520) Steam Expenses
28
SteamFromOtherSourcesNuclearPowerGeneration
(521) Steam from Other Sources
29
SteamTransferredCreditNuclearPowerGeneration
(Less) (522) Steam Transferred-Cr.
30
ElectricExpensesNuclearPowerGeneration
(523) Electric Expenses
31
MiscellaneousNuclearPowerExpenses
(524) Miscellaneous Nuclear Power Expenses
2,190,736
3,463,925
32
RentsNuclearPowerGeneration
(525) Rents
113,532
33
NuclearPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of lines 24 thru 32)
2,077,204
3,473,225
34
NuclearPowerGenerationMaintenanceAbstract
Maintenance
35
MaintenanceSupervisionAndEngineeringNuclearPowerGeneration
(528) Maintenance Supervision and Engineering
150,432
177,358
36
MaintenanceOfStructuresNuclearPowerGeneration
(529) Maintenance of Structures
37
MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration
(530) Maintenance of Reactor Plant Equipment
12,232
38
MaintenanceOfElectricPlantNuclearPowerGeneration
(531) Maintenance of Electric Plant
39
MaintenanceOfMiscellaneousNuclearPlant
(532) Maintenance of Miscellaneous Nuclear Plant
2,352
40
NuclearPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 35 thru 39)
152,784
165,126
41
PowerProductionExpensesNuclearPower
TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
2,229,988
3,308,099
42
HydraulicPowerGenerationAbstract
C. Hydraulic Power Generation
43
HydraulicPowerGenerationOperationAbstract
Operation
44
OperationSupervisionAndEngineeringHydraulicPowerGeneration
(535) Operation Supervision and Engineering
45
WaterForPower
(536) Water for Power
46
HydraulicExpenses
(537) Hydraulic Expenses
47
ElectricExpensesHydraulicPowerGeneration
(538) Electric Expenses
48
MiscellaneousHydraulicPowerGenerationExpenses
(539) Miscellaneous Hydraulic Power Generation Expenses
49
RentsHydraulicPowerGeneration
(540) Rents
50
HydraulicPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 44 thru 49)
51
HydraulicPowerGenerationContinuedAbstract
C. Hydraulic Power Generation (Continued)
52
HydraulicPowerGenerationMaintenanceAbstract
Maintenance
53
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
(541) Mainentance Supervision and Engineering
54
MaintenanceOfStructuresHydraulicPowerGeneration
(542) Maintenance of Structures
55
MaintenanceOfReservoirsDamsAndWaterways
(543) Maintenance of Reservoirs, Dams, and Waterways
56
MaintenanceOfElectricPlantHydraulicPowerGeneration
(544) Maintenance of Electric Plant
57
MaintenanceOfMiscellaneousHydraulicPlant
(545) Maintenance of Miscellaneous Hydraulic Plant
58
HydraulicPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 53 thru 57)
59
PowerProductionExpensesHydraulicPower
TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
60
OtherPowerGenerationAbstract
D. Other Power Generation
61
OtherPowerGenerationOperationAbstract
Operation
62
OperationSupervisionAndEngineeringOtherPowerGeneration
(546) Operation Supervision and Engineering
260,143
308,942
63
Fuel
(547) Fuel
1,488,814
3,046,408
64
GenerationExpenses
(548) Generation Expenses
64.1
OperationOfEnergyStorageEquipment
(548.1) Operation of Energy Storage Equipment
65
MiscellaneousOtherPowerGenerationExpenses
(549) Miscellaneous Other Power Generation Expenses
3,815,706
5,092,124
66
RentsOtherPowerGeneration
(550) Rents
306
67
OtherPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 62 thru 67)
5,564,969
8,447,474
68
OtherPowerGenerationMaintenanceAbstract
Maintenance
69
MaintenanceSupervisionAndEngineeringOtherPowerGeneration
(551) Maintenance Supervision and Engineering
70
MaintenanceOfStructures
(552) Maintenance of Structures
64,982
125,311
71
MaintenanceOfGeneratingAndElectricPlant
(553) Maintenance of Generating and Electric Plant
6,900,692
7,477,951
71.1
MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration
(553.1) Maintenance of Energy Storage Equipment
72
MaintenanceOfMiscellaneousOtherPowerGenerationPlant
(554) Maintenance of Miscellaneous Other Power Generation Plant
13,744,866
6,360,616
73
OtherPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 69 thru 72)
20,580,576
13,963,878
74
PowerProductionExpensesOtherPower
TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)
26,145,545
22,411,352
75
OtherPowerSuplyExpensesAbstract
E. Other Power Supply Expenses
76
PurchasedPower
(555) Purchased Power
1,684,386,068
1,712,801,101
76.1
PowerPurchasedForStorageOperations
(555.1) Power Purchased for Storage Operations
0
77
SystemControlAndLoadDispatchingElectric
(556) System Control and Load Dispatching
1,573,613
2,165,143
78
OtherExpensesOtherPowerSupplyExpenses
(557) Other Expenses
6,938,917
5,914,678
79
OtherPowerSupplyExpense
TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)
1,692,898,598
1,720,880,922
80
PowerProductionExpenses
TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)
1,881,941,291
1,849,081,274
81
TransmissionExpensesAbstract
2. TRANSMISSION EXPENSES
82
TransmissionExpensesOperationAbstract
Operation
83
OperationSupervisionAndEngineeringElectricTransmissionExpenses
(560) Operation Supervision and Engineering
9,551,648
6,646,021
85
LoadDispatchReliability
(561.1) Load Dispatch-Reliability
872,180
818,282
86
LoadDispatchMonitorAndOperateTransmissionSystem
(561.2) Load Dispatch-Monitor and Operate Transmission System
1,592,020
1,544,638
87
LoadDispatchTransmissionServiceAndScheduling
(561.3) Load Dispatch-Transmission Service and Scheduling
122,504
132,130
88
SchedulingSystemControlAndDispatchServices
(561.4) Scheduling, System Control and Dispatch Services
3,844,368
5,200,324
89
ReliabilityPlanningAndStandardsDevelopment
(561.5) Reliability, Planning and Standards Development
84,087
82,101
90
TransmissionServiceStudies
(561.6) Transmission Service Studies
91
GenerationInterconnectionStudies
(561.7) Generation Interconnection Studies
2,022
92
ReliabilityPlanningAndStandardsDevelopmentServices
(561.8) Reliability, Planning and Standards Development Services
2,540,191
3,058,271
93
StationExpensesTransmissionExpense
(562) Station Expenses
8,258,672
6,458,357
93.1
OperationOfEnergyStorageEquipmentTransmissionExpense
(562.1) Operation of Energy Storage Equipment
94
OverheadLineExpense
(563) Overhead Lines Expenses
10,149,410
9,764,840
95
UndergroundLineExpensesTransmissionExpense
(564) Underground Lines Expenses
58,883
51,420
96
TransmissionOfElectricityByOthers
(565) Transmission of Electricity by Others
97
MiscellaneousTransmissionExpenses
(566) Miscellaneous Transmission Expenses
17,591,239
14,538,153
98
RentsTransmissionElectricExpense
(567) Rents
3,946,818
2,779,304
99
TransmissionOperationExpense
TOTAL Operation (Enter Total of Lines 83 thru 98)
58,612,020
51,075,863
100
TransmissionMaintenanceAbstract
Maintenance
101
MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses
(568) Maintenance Supervision and Engineering
1,949,278
1,772,731
102
MaintenanceOfStructuresTransmissionExpense
(569) Maintenance of Structures
529,448
567,231
103
MaintenanceOfComputerHardwareTransmission
(569.1) Maintenance of Computer Hardware
1,034,457
857,038
104
MaintenanceOfComputerSoftwareTransmission
(569.2) Maintenance of Computer Software
3,015,796
1,623,687
105
MaintenanceOfCommunicationEquipmentElectricTransmission
(569.3) Maintenance of Communication Equipment
52
65
106
MaintenanceOfMiscellaneousRegionalTransmissionPlant
(569.4) Maintenance of Miscellaneous Regional Transmission Plant
173,122
156,270
107
MaintenanceOfStationEquipmentTransmission
(570) Maintenance of Station Equipment
19,573,862
15,716,966
107.1
MaintenanceOfEnergyStorageEquipmentTransmission
(570.1) Maintenance of Energy Storage Equipment
108
MaintenanceOfOverheadLinesTransmission
(571) Maintenance of Overhead Lines
24,432,908
26,863,352
109
MaintenanceOfUndergroundLinesTransmission
(572) Maintenance of Underground Lines
423,899
1,113,175
110
MaintenanceOfMiscellaneousTransmissionPlant
(573) Maintenance of Miscellaneous Transmission Plant
11,490
5,599
111
TransmissionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 101 thru 110)
51,144,312
48,676,114
112
TransmissionExpenses
TOTAL Transmission Expenses (Total of Lines 99 and 111)
109,756,332
99,751,977
113
RegionalMarketExpensesAbstract
3. REGIONAL MARKET EXPENSES
114
RegionalMarketExpensesOperationAbstract
Operation
115
OperationSupervision
(575.1) Operation Supervision
116
DayAheadAndRealTimeMarketAdministration
(575.2) Day-Ahead and Real-Time Market Facilitation
117
TransmissionRightsMarketAdministration
(575.3) Transmission Rights Market Facilitation
118
CapacityMarketAdministration
(575.4) Capacity Market Facilitation
119
AncillaryServicesMarketAdministration
(575.5) Ancillary Services Market Facilitation
120
MarketMonitoringAndCompliance
(575.6) Market Monitoring and Compliance
121
MarketFacilitationMonitoringAndComplianceServices
(575.7) Market Facilitation, Monitoring and Compliance Services
2,743,013
3,171,002
122
RentsRegionalMarketExpenses
(575.8) Rents
123
RegionalMarketOperationExpense
Total Operation (Lines 115 thru 122)
2,743,013
3,171,002
124
RegionalMarketExpensesMaintenanceAbstract
Maintenance
125
MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses
(576.1) Maintenance of Structures and Improvements
126
MaintenanceOfComputerHardware
(576.2) Maintenance of Computer Hardware
127
MaintenanceOfComputerSoftware
(576.3) Maintenance of Computer Software
128
MaintenanceOfCommunicationEquipmentRegionalMarketExpenses
(576.4) Maintenance of Communication Equipment
129
MaintenanceOfMiscellaneousMarketOperationPlant
(576.5) Maintenance of Miscellaneous Market Operation Plant
130
RegionalMarketMaintenanceExpense
Total Maintenance (Lines 125 thru 129)
131
RegionalMarketExpenses
TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)
2,743,013
3,171,002
132
DistributionExpensesAbstract
4. DISTRIBUTION EXPENSES
133
DistributionExpensesOperationAbstract
Operation
134
OperationSupervisionAndEngineeringDistributionExpense
(580) Operation Supervision and Engineering
26,150,160
26,626,900
135
LoadDispatching
(581) Load Dispatching
1,417,246
2,959,973
136
StationExpensesDistribution
(582) Station Expenses
4,666,542
6,583,947
137
OverheadLineExpenses
(583) Overhead Line Expenses
7,633,427
12,787,071
138
UndergroundLineExpenses
(584) Underground Line Expenses
5,508,523
6,676,999
138.1
OperationOfEnergyStorageEquipmentDistribution
(584.1) Operation of Energy Storage Equipment
139
StreetLightingAndSignalSystemExpenses
(585) Street Lighting and Signal System Expenses
840,442
652,415
140
MeterExpenses
(586) Meter Expenses
11,779,667
11,116,044
141
CustomerInstallationsExpenses
(587) Customer Installations Expenses
4,446,868
5,133,100
142
MiscellaneousDistributionExpenses
(588) Miscellaneous Expenses
87,876,495
61,840,999
143
RentsDistributionExpense
(589) Rents
310,830
473,746
144
DistributionOperationExpensesElectric
TOTAL Operation (Enter Total of Lines 134 thru 143)
150,630,200
134,851,194
145
DistributionExpensesMaintenanceAbstract
Maintenance
146
MaintenanceSupervisionAndEngineering
(590) Maintenance Supervision and Engineering
829,325
2,299,907
147
MaintenanceOfStructuresDistributionExpense
(591) Maintenance of Structures
150
170
148
MaintenanceOfStationEquipment
(592) Maintenance of Station Equipment
6,283,430
4,389,418
148.1
MaintenanceOfEnergyStorageEquipment
(592.2) Maintenance of Energy Storage Equipment
149
MaintenanceOfOverheadLines
(593) Maintenance of Overhead Lines
108,643,725
149,925,139
150
MaintenanceOfUndergroundLines
(594) Maintenance of Underground Lines
16,914,676
17,854,802
151
MaintenanceOfLineTransformers
(595) Maintenance of Line Transformers
239,501
5,658
152
MaintenanceOfStreetLightingAndSignalSystems
(596) Maintenance of Street Lighting and Signal Systems
7,410
220,135
153
MaintenanceOfMeters
(597) Maintenance of Meters
1,684,599
1,531,236
154
MaintenanceOfMiscellaneousDistributionPlant
(598) Maintenance of Miscellaneous Distribution Plant
4,382,733
5,587,114
155
DistributionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 146 thru 154)
138,985,549
181,813,579
156
DistributionExpenses
TOTAL Distribution Expenses (Total of Lines 144 and 155)
289,615,749
316,664,773
157
CustomerAccountsExpensesAbstract
5. CUSTOMER ACCOUNTS EXPENSES
158
CustomerAccountsExpensesOperationsAbstract
Operation
159
SupervisionCustomerAccountExpenses
(901) Supervision
396
766
160
MeterReadingExpenses
(902) Meter Reading Expenses
2,246,141
2,075,012
161
CustomerRecordsAndCollectionExpenses
(903) Customer Records and Collection Expenses
67,040,791
43,546,162
162
UncollectibleAccounts
(904) Uncollectible Accounts
11,370,178
40,294,644
163
MiscellaneousCustomerAccountsExpenses
(905) Miscellaneous Customer Accounts Expenses
261,608
266,677
164
CustomerAccountExpenses
TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)
80,919,114
86,183,261
165
CustomerServiceAndInformationalExpensesAbstract
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166
CustomerServiceAndInformationalExpensesOperationAbstract
Operation
167
SupervisionCustomerServiceAndInformationExpenses
(907) Supervision
168
CustomerAssistanceExpenses
(908) Customer Assistance Expenses
187,561,814
132,620,477
169
InformationalAndInstructionalAdvertisingExpenses
(909) Informational and Instructional Expenses
747,786
821,722
170
MiscellaneousCustomerServiceAndInformationalExpenses
(910) Miscellaneous Customer Service and Informational Expenses
1,563,859
1,872,681
171
CustomerServiceAndInformationExpenses
TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)
189,873,459
135,314,880
172
SalesExpenseAbstract
7. SALES EXPENSES
173
SalesExpenseOperationAbstract
Operation
174
SupervisionSalesExpense
(911) Supervision
175
DemonstratingAndSellingExpenses
(912) Demonstrating and Selling Expenses
155,328
157,477
176
AdvertisingExpenses
(913) Advertising Expenses
177
MiscellaneousSalesExpenses
(916) Miscellaneous Sales Expenses
178
SalesExpenses
TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)
155,328
157,477
179
AdministrativeAndGeneralExpensesAbstract
8. ADMINISTRATIVE AND GENERAL EXPENSES
180
AdministrativeAndGeneralExpensesOperationAbstract
Operation
181
AdministrativeAndGeneralSalaries
(920) Administrative and General Salaries
62,282,647
46,411,109
182
OfficeSuppliesAndExpenses
(921) Office Supplies and Expenses
33,307,565
28,861,000
183
AdministrativeExpensesTransferredCredit
(Less) (922) Administrative Expenses Transferred-Credit
20,277,083
18,872,382
184
OutsideServicesEmployed
(923) Outside Services Employed
108,586,773
108,535,259
185
PropertyInsurance
(924) Property Insurance
8,615,717
8,310,402
186
InjuriesAndDamages
(925) Injuries and Damages
215,579,218
181,130,339
187
EmployeePensionsAndBenefits
(926) Employee Pensions and Benefits
56,506,011
62,304,380
188
FranchiseRequirements
(927) Franchise Requirements
128,579,841
130,506,765
189
RegulatoryCommissionExpenses
(928) Regulatory Commission Expenses
35,379,656
27,995,793
190
DuplicateChargesCredit
(929) (Less) Duplicate Charges-Cr.
12,933,801
2,772,785
191
GeneralAdvertisingExpenses
(930.1) General Advertising Expenses
66,135
204,155
192
MiscellaneousGeneralExpenses
(930.2) Miscellaneous General Expenses
10,538,715
2,511,055
193
RentsAdministrativeAndGeneralExpense
(931) Rents
12,351,503
10,939,305
194
AdministrativeAndGeneralOperationExpense
TOTAL Operation (Enter Total of Lines 181 thru 193)
638,582,897
585,656,085
195
AdministrativeAndGeneralExpensesMaintenanceAbstract
Maintenance
196
MaintenanceOfGeneralPlant
(935) Maintenance of General Plant
18,209,169
9,293,298
197
AdministrativeAndGeneralExpenses
TOTAL Administrative & General Expenses (Total of Lines 194 and 196)
656,792,066
594,949,383
198
OperationsAndMaintenanceExpensesElectric
TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)
3,211,485,696
3,085,274,027


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
PURCHASED POWER (Account 555)
  1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
  2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
  3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

    RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers.

    LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract.

    IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years.

    SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less.

    LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit.

    IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years.

    EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges.

    OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment.

    AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment.

  4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided.
  5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
  6. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
  7. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote.
  8. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13.
  9. Footnote entries as required and provide explanations following all required data.
Actual Demand (MW) POWER EXCHANGES COST/SETTLEMENT OF POWER
Line No.
NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Name of Company or Public Authority (Footnote Affiliations)
(a)
StatisticalClassificationCode
Statistical Classification
(b)
RateScheduleTariffNumber
Ferc Rate Schedule or Tariff Number
(c)
AverageMonthlyBillingDemand
Average Monthly Billing Demand (MW)
(d)
AverageMonthlyNonCoincidentPeakDemand
Average Monthly NCP Demand
(e)
AverageMonthlyCoincidentPeakDemand
Average Monthly CP Demand
(f)
MegawattHoursPurchasedOtherThanStorage
MegaWatt Hours Purchased (Excluding for Energy Storage)
(g)
MegawattHoursPurchasedForEnergyStorage
MegaWatt Hours Purchased for Energy Storage
(h)
EnergyReceivedThroughPowerExchanges
MegaWatt Hours Received
(i)
EnergyDeliveredThroughPowerExchanges
MegaWatt Hours Delivered
(j)
DemandChargesOfPurchasedPower
Demand Charges ($)
(k)
EnergyChargesOfPurchasedPower
Energy Charges ($)
(l)
OtherChargesOfPurchasedPower
Other Charges ($)
(m)
SettlementOfPower
Total (k+l+m) of Settlement ($)
(n)
1
Alta Oak Realty
361,366
(a)
357,954
454
357,500
2
Arlington Valley Solar II LLC
47,377
(b)
42,070,922
833,224
42,904,146
3
California ISO
11,274,753
(c)
705,571,949
16,853,857
688,718,092
4
Calipatria LLC
47,377
(d)
3,506,449
181,540
3,687,989
5
Calpeak Power LLC
495
2,565,019
2,565,019
6
Campo Verde Solar LLC
347,952
(e)
42,378,458
141,231
42,519,689
7
Carlsbad Energy Center LLC
441,732
103,696,176
33,636,264
137,332,440
8
Cascade Solar LLC
53,541
(f)
4,530,821
5,671
4,525,150
9
Catalina Solar LLC
250,128
(g)
33,699,692
25,302
33,674,390
10
Centinela Solar Energy LLC
373,289
(h)
51,438,888
271,962
51,710,850
11
Centinela Solar Energy 2 LLC
132,717
18,304,624
72,445
18,377,069
12
City of Escondido (Bear Valley Hydro)
496
6,644
22,826
29,470
13
City of Oceanside (San Francisco Peak Hydro)
147
1,617
10,227
11,844
14
Clean Power Alliance of SoCal
0
1,594,294
1,594,294
15
Coram Energy LLC
24,624
(i)
2,539,412
2,464
2,536,948
16
CP Kelco US Inc
7,656
80,861
457,447
538,308
17
CSolar IV South LLC
292,930
(j)
40,753,334
309,065
41,062,399
18
CSolar IV West LLC
402,034
(k)
44,077,187
137,062
44,214,249
19
Desert Green Solar Farm LLC
11,989
(l)
1,676,280
2,075
1,674,205
20
El Cajon Energy Center (Tolling)
6,659
7,269,412
810,146
8,079,558
21
Energia Sierra Juarez US LLC
426,207
(m)
43,780,556
440,695
44,221,251
22
Escondido Energy Center LLC
8,675
7,774,511
942,127
8,716,638
23
Goal Line LP
17,362
11,109,931
1,284,369
12,394,300
24
Grossmont Hospital Corporation
3,063
14,280
172,878
187,158
25
HL Power Company LP
149,030
15,751,724
15,751,724
26
Imperial Valley Solar I LLC (Mount Signal)
370,438
(n)
43,243,088
153,095
43,396,183
27
Kumeyaay Wind LLC
152,648
180,360
(o)
7,824,988
147,421
8,152,769
28
Manzana Wind LLC
293,789
13,959,598
13,959,598
29
Maricopa West Solar PV LLC
36,899
(p)
2,522,526
3,772
2,518,754
30
Midway Solar
50,544
93
(q)
2,401,500
174,368
2,575,961
31
MM Prima Deshecha Energy LLC
44,919
318,413
318,413
32
MM San Diego LLC (Miramar RAM)
27,086
2,096,183
2,096,183
33
Morgan Stanley Capital Group
750,322
34
Naturener Glacier Wind Energy 1 LLC
263,833
263,833
5,540,490
5,540,490
35
Naturener Glacier Wind Energy 2 LLC
283,544
283,544
8,506,313
8,506,313
36
Naturener Rim Rock Wind Energy LLC
644,935
644,935
28,370,668
28,370,668
37
NLP Valley Center Solar LLC
5,831
(r)
642,129
588
641,541
38
NLP Granger A82 LLC
7,259
(s)
768,221
734
767,487
39
Oak Creek Wind Power LLC
265
(t)
55,047
126
54,921
40
Ocotillo Express LLC
439,172
(u)
42,636,820
37,529
42,599,291
41
Olivenhain Muni Water District
869
108,974
108,974
42
Orange Grove Energy Center (Tolling)
14,858
17,051,016
1,001,117
18,052,133
43
Otay Mesa Energy Center (Tolling)
0
49,670,244
40,685
49,710,929
44
Pacific Wind Lessee LLC
332,125
(v)
38,083,355
227,924
38,311,279
45
Pio Pico Energy Center
75,539
66,587,956
5,891,649
72,479,605
46
San Diego County Water Authority -Olivenhain-Hodges
20,497
2,663,644
415,700
3,079,344
47
San Gorgonio Westwinds II LLC
37,822
(w)
2,619,971
3,651
2,616,320
48
San Marcos Energy LLC
11,827
1,296
1,388,365
1,389,661
49
SG2 Imperial Valley LLC
423,602
1,081,800
(x)
30,216,143
1,889,859
33,187,802
50
Sol Orchard 20 LLC (Ramona 1)
4,529
(y)
607,743
459
607,284
51
Sol Orchard 21 LLC (Ramona 2)
11,784
(z)
1,583,764
1,075
1,582,689
52
Sol Orchard 22 LLC (Valley Center 1)
5,651
(aa)
760,836
568
760,268
53
Sol Orchard 23 LLC (Valley Center 2)
11,895
(ab)
1,602,650
1,194
1,601,456
54
Solar Borrego LLC
69,557
(ac)
9,575,922
418,887
9,994,809
55
Sycamore Energy 1 LLC
6,232
689
733,744
733,055
56
Sycamore Energy 2 LLC
18,071
1,911
1,550,868
1,552,779
57
Tallbear Seville LLC
60,747
(ad)
4,896,973
147,954
5,044,927
58
TransAlta Energy Marketing
70,346
3,593,911
3,593,911
59
Yuma Co-generator Association
70,346
10,073,807
9,227,842
19,301,649
60
Calpine Energy Services
212,140
2,326,478
2,538,618
61
Elk Hills Power, LLC
10,193
10,193
62
Marin Clean Energy
10,678
10,678
63
Morgan Stanley Capital Group Inc
26,473,587
26,473,587
64
Pacific Gas & Electric Co.
67,725
67,725
65
Peninsula Clean Energy Authority
58,000
58,000
66
Sempra Gas & Power Marketing LLC
25,587,552
25,587,552
67
Sentinel Energy
3,290,212
3,290,212
68
Southern California Edison Company
90,750
90,750
69
Valley Center Storage I
678,285
678,285
70
Valley Center Storage II
1,808,719
1,808,719
71
Vista Energy Storage
803,962
0
803,962
72
Procurement software
73
Broker Fees
12,000
12,000
74
Hedging Activity
221,314
221,314
75
Columbia Power Consulting
15,082,064
15,082,064
76
Montrose Air Quality Services
1,950
1,950
77
GHG Allowances
9,500
9,500
78
Misc. Adjustment
17,043,480
17,043,480
79
Counterparty Deposits
2
2
80
Green Tariff Entries
0
60,000
60,000
81
0
15 TOTAL
18,066,074
0
1,192,312
1,192,312
304,271,879
1,389,320,110
9,205,924
1,684,386,065


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(b) Concept: EnergyChargesOfPurchasedPower
Curtailment of 8,076 MWh and payment/penalties of $855,987. Forecasting fees.
(c) Concept: EnergyChargesOfPurchasedPower
CAISO allocated revenues and charges.
(d) Concept: EnergyChargesOfPurchasedPower
Curtailment of 3,622 MWh and payment/penalties of $198,574. Forecasting fees.
(e) Concept: EnergyChargesOfPurchasedPower
Curtailment of 2,325 MWh and payment/penalties of $185,033. Forecasting fees.
(f) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(g) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(h) Concept: EnergyChargesOfPurchasedPower
Curtailment of 3,351 MWh and payment/penalties of $410,210. Forecasting fees..
(i) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(j) Concept: EnergyChargesOfPurchasedPower
Curtailment of 3,260 MWh and payment/penalties of $356,638. Forecasting fees.
(k) Concept: EnergyChargesOfPurchasedPower
Curtailment of 2,811 MWh and payment/penalties of $214,115. Forecasting fees.
(l) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(m) Concept: EnergyChargesOfPurchasedPower
Curtailment of 6,059 MWh and payment/penalties of $526,155. Forecasting fees.
(n) Concept: EnergyChargesOfPurchasedPower
Curtailment of 2,436 MWh and payments/penalties of $190,204. Forecasting fees..
(o) Concept: EnergyChargesOfPurchasedPower
Curtailment of 1,655 MWh and payment/penalties of $73,732. Forecasting fees. OMS Curtailment.
(p) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(q) Concept: EnergyChargesOfPurchasedPower
Curtailment of 3,514 MWh and payment/penalties of $200,649. Forecasting fees.
(r) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(s) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(t) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(u) Concept: EnergyChargesOfPurchasedPower
Curtailment of 56 MWh and payments/penalties of $7,078. Forecasting fees.
(v) Concept: EnergyChargesOfPurchasedPower
Curtailment of 2,357 MWh and payments/penalties of $265,903. Forecasting fees.
(w) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(x) Concept: EnergyChargesOfPurchasedPower
Curtailment of 17,155 MWh and payments/penalties of $1,889,859.
(y) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(z) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(aa) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(ab) Concept: EnergyChargesOfPurchasedPower
Forecasting fees.
(ac) Concept: EnergyChargesOfPurchasedPower
Curtailment of 3,350 MWh and payment/penalties of $431,222. Forecasting fees.
(ad) Concept: EnergyChargesOfPurchasedPower
Curtailment of 484 MWh and payments/penalties of $176,561. Forecasting fees.
(ae) Concept: EnergyChargesOfPurchasedPower
Software & support
(af) Concept: EnergyChargesOfPurchasedPower
Contract administration expenses.
(ag) Concept: EnergyChargesOfPurchasedPower
Contract hedging activity.
(ah) Concept: EnergyChargesOfPurchasedPower
Engineering services.
(ai) Concept: EnergyChargesOfPurchasedPower
Environmental Services
(aj) Concept: EnergyChargesOfPurchasedPower
Amortization of GHG Allowances.
(ak) Concept: EnergyChargesOfPurchasedPower
EPA activity
(al) Concept: EnergyChargesOfPurchasedPower
Retained counterparty deposits

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
  1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
  3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
  4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
  5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
  6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
  7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
  8. Report in column (i) and (j) the total megawatthours received and delivered.
  9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
  10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
  11. Footnote entries and provide explanations following all required data.
TRANSFER OF ENERGY REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.
PaymentByCompanyOrPublicAuthority
Payment By (Company of Public Authority) (Footnote Affiliation)
(a)
TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Energy Received From (Company of Public Authority) (Footnote Affiliation)
(b)
TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Energy Delivered To (Company of Public Authority) (Footnote Affiliation)
(c)
StatisticalClassificationCode
Statistical Classification
(d)
RateScheduleTariffNumber
Ferc Rate Schedule of Tariff Number
(e)
TransmissionPointOfReceipt
Point of Receipt (Substation or Other Designation)
(f)
TransmissionPointOfDelivery
Point of Delivery (Substation or Other Designation)
(g)
BillingDemand
Billing Demand (MW)
(h)
TransmissionOfElectricityForOthersEnergyReceived
Megawatt Hours Received
(i)
TransmissionOfElectricityForOthersEnergyDelivered
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
RevenuesFromTransmissionOfElectricityForOthers
Total Revenues ($) (k+l+m)
(n)
1
CAISO
N/A
N/A
N/A
N/A
316,575,181
316,575,181
35 TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
TRANSMISSION OF ELECTRICITY BY ISO/RTOs
  1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).
  3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
  4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided.
  5. In column (d) report the revenue amounts as shown on bills or vouchers.
  6. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.
Payment Received by (Transmission Owner Name)
(a)
Statistical Classification
(b)
FERC Rate Schedule or Tariff Number
(c)
Total Revenue by Rate Schedule or Tariff
(d)
Total Revenue
(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40
TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
  1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter.
  2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported.
  3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
    FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
  4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
  5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
  6. Enter ""TOTAL"" in column (a) as the last line.
  7. Footnote entries and provide explanations following all required data.
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.
NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Name of Company or Public Authority (Footnote Affiliations)
(a)
StatisticalClassificationCode
Statistical Classification
(b)
TransmissionOfElectricityByOthersEnergyReceived
MegaWatt Hours Received
(c)
TransmissionOfElectricityByOthersEnergyDelivered
MegaWatt Hours Delivered
(d)
DemandChargesTransmissionOfElectricityByOthers
Demand Charges ($)
(e)
EnergyChargesTransmissionOfElectricityByOthers
Energy Charges ($)
(f)
OtherChargesTransmissionOfElectricityByOthers
Other Charges ($)
(g)
ChargesForTransmissionOfElectricityByOthers
Total Cost of Transmission ($)
(h)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
TOTAL


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.
Description
(a)
Amount
(b)
1
IndustryAssociationDues
Industry Association Dues
958,139
2
NuclearPowerResearchExpenses
Nuclear Power Research Expenses
3
OtherExperimentalAndGeneralResearchExpenses
Other Experimental and General Research Expenses
4
PublicationAndDistributionExpensesForSecuritiesToStockholders
Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5
OtherMiscellaneousGeneralExpenses
Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6
Abandoned Projects
5,025,366
7
Cost of Financing
2,296,550
8
Other Expenses
2,258,660
46
MiscellaneousGeneralExpenses
TOTAL
10,538,715


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
  1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403); (c) Depreciation Expense for Asset Retirement Costs (Account 403.1); (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405).
  2. Report in Section B the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
  3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year.
    Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used.
    In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used.
    For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type of mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
  4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Line No.
FunctionalClassificationAxis
Functional Classification
(a)
DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments
Depreciation Expense (Account 403)
(b)
DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments
Depreciation Expense for Asset Retirement Costs (Account 403.1)
(c)
AmortizationOfLimitedTermPlantOrProperty
Amortization of Limited Term Electric Plant (Account 404)
(d)
AmortizationOfOtherElectricPlant
Amortization of Other Electric Plant (Acc 405)
(e)
DepreciationAndAmortization
Total
(f)
1
Intangible Plant
15,043,789
15,043,789
2
Steam Production Plant
25,183,299
25,183,299
3
Nuclear Production Plant
4
Hydraulic Production Plant-Conventional
5
Hydraulic Production Plant-Pumped Storage
6
Other Production Plant
27,822,430
27,822,430
7
Transmission Plant
210,002,612
1,949,507
211,952,119
8
Distribution Plant
317,767,256
2,067,623
319,834,879
9
Regional Transmission and Market Operation
10
General Plant
22,351,711
22,351,711
11
Common Plant-Electric
56,368,616
67,509,038
123,877,654
12
TOTAL
659,495,924
82,552,827
4,017,130
(a)
746,065,881
B. Basis for Amortization Charges
Account 404The amortization of Intangible Plant (software) is based on the anticipated useful life of the software project.Account 405The amortization of Land Rights is based on the anticipated useful lives of the rights-of-way.
C. Factors Used in Estimating Depreciation Charges
Line No.
AccountNumberFactorsUsedInEstimatingDepreciationCharges
Account No.
(a)
DepreciablePlantBase
Depreciable Plant Base (in Thousands)
(b)
UtilityPlantEstimatedAverageServiceLife
Estimated Avg. Service Life
(c)
UtilityPlantNetSalvageValuePercentage
Net Salvage (Percent)
(d)
UtilityPlantAppliedDepreciationRate
Applied Depr. Rates (Percent)
(e)
MortalityCurveType
Mortality Curve Type
(f)
UtilityPlantWeightedAverageRemainingLife
Average Remaining Life
(g)
12
13
29.453
30 years
10.58
6.71
SQ
5 years, 3 months, 18 days
14
61.963
30 years
2.3
3.81
SQ
15 years, 6 months
15
56.058
30 years
4.27
6.85
SQ
5 years, 3 months, 18 days
16
107.51
30 years
2.3
3.36
SQ
15 years, 6 months
17
16.507
30 years
10.49
9.24
SQ
5 years, 3 months, 18 days
18
116.366
30 years
1.41
3.6
SQ
15 years, 6 months
19
49.704
30 years
0.08
6.98
SQ
5 years, 3 months, 18 days
20
37.258
30 years
0.32
3.42
SQ
15 years, 6 months
21
5.263
30 years
0.7
8
SQ
5 years, 3 months, 18 days
22
57.48
30 years
0.25
4.49
SQ
15 years, 6 months
23
537.562
24
25
1.896
25 years
17.45
9.46
SQ
6 years, 6 months
26
3.005
30 years
30.74
16.58
SQ
5 years, 3 months, 18 days
27
5.076
25 years
6.76
4.84
SQ
11 years, 6 months
28
14.82
30 years
3.29
3.81
SQ
15 years, 6 months
29
0.072
25 years
4
SQ
0 years
30
0.627
25 years
5.02
7.65
SQ
6 years, 6 months
31
0.878
30 years
24.16
11.85
SQ
5 years, 3 months, 18 days
32
5.233
25 years
2.92
4.51
SQ
11 years, 6 months
33
14.914
30 years
1.45
3.7
SQ
15 years, 6 months
34
16.859
25 years
8.09
SQ
6 years, 6 months
35
24.382
30 years
6.07
SQ
5 years, 3 months, 18 days
36
53.287
25 years
4.16
SQ
11 years, 6 months
37
30 years
SQ
15 years, 6 months
38
6.096
25 years
9.07
13.31
SQ
6 years, 6 months
39
108.731
30 years
0.42
5.28
SQ
5 years, 3 months, 18 days
40
19.736
25 years
2.61
4.98
SQ
11 years, 6 months
41
156.883
30 years
0.6
3.39
SQ
15 years, 6 months
42
58.683
25 years
4.07
SQ
17 years, 4 months, 24 days
43
1.767
20 years
5.03
SQ
12 years, 6 months
44
0.834
25 years
14.47
8.54
SQ
6 years, 6 months
45
9.572
30 years
4.71
5.32
SQ
5 years, 3 months, 18 days
46
13.461
25 years
1.08
4.25
SQ
11 years, 6 months
47
6.706
30 years
3.06
3.28
SQ
15 years, 6 months
48
2.332
25 years
4
SQ
12 years, 7 months, 6 days
49
20 years
5
SQ
0 years
50
5.071
25 years
11.25
SQ
6 years, 6 months
51
22.374
30 years
5.14
SQ
5 years, 3 months, 18 days
52
11.908
25 years
7.18
SQ
11 years, 6 months
53
19.644
30 years
6.16
SQ
15 years, 6 months
54
584.847
55
56
40.83
74 years
75
2.18
R2.5
54 years, 7 months, 6 days
57
327.314
50 years
70
3.49
R1.5
40 years, 7 months, 6 days
58
62.029
70 years
75
2.02
R5
36 years, 6 months
59
10.306
45 years
100
3.4
R1.5
25 years, 6 months
60
46.685
64 years
100
1.42
R2
38 years, 4 months, 24 days
61
5.324
60 years
1.51
SQ
31 years, 7 months, 6 days
62
492.488
63
64
124.028
74 years
75
2.41
R2.5
68 years, 9 months, 18 days
65
164.627
50 years
70
3.48
R1.5
45 years, 7 months, 6 days
66
766.912
70 years
75
2.57
R5
64 years, 6 months
67
3.344
45 years
100
4.51
R1.5
40 years, 6 months
68
173.454
64 years
100
3.22
R2
58 years, 9 months, 18 days
69
80.523
60 years
30
2.2
R5
54 years, 6 months
70
126.452
50 years
10
2.19
R2
45 years, 1 month, 6 days
71
241.126
60 years
1.66
SQ
54 years, 6 months
72
1,680.466
73
74
532.127
74 years
75
2.37
R2.5
67 years, 10 months, 24 days
75
1,565.85
50 years
70
3.49
R1.5
43 years, 6 months
76
1.42
50 years
70
3.64
R1.5
40 years, 1 month, 6 days
77
96.717
70 years
75
2.36
R5
48 years, 10 months, 24 days
78
933.766
45 years
100
4.57
R1.5
39 years, 9 months, 18 days
79
619.36
64 years
100
3.03
R2
53 years, 9 months, 18 days
80
474.566
60 years
30
2.14
R5
52 years
81
439.061
50 years
10
2.13
R2
43 years, 6 months
82
123.913
60 years
1.69
SQ
52 years, 9 months, 18 days
83
4,786.78
84
85
12.899
63 years
125
3.77
R2.5
54 years, 10 months, 24 days
86
641.548
51 years
125
4.62
R1.5
39 years, 9 months, 18 days
87
155.273
10 years
9.85
SQ
5 years, 9 months, 18 days
88
976.408
47 years
100
4.21
R0.5
39 years, 9 months, 18 days
89
1,049.006
55 years
70
2.98
R0.5
48 years, 4 months, 24 days
90
1,636.908
57 years
50
2.65
R3
43 years, 1 month, 6 days
91
1,884.43
45 years
65
3.52
R3
30 years, 9 months, 18 days
92
742.302
34 years
70
5.22
L0.5
26 years, 1 month, 6 days
93
33.857
12 years
70
16.36
L0
7 years, 9 months, 18 days
94
257.03
55 years
110
3.44
R0.5
47 years, 3 months, 18 days
95
398.29
53 years
75
3.08
L4
34 years, 1 month, 6 days
96
7.701
48 years
2.08
R0.5
44 years, 7 months, 6 days
97
202.551
15 years
6.65
SQ
5 years, 3 months, 18 days
98
9.376
48 years
2.18
R0.5
45 years, 1 month, 6 days
99
61.203
15 years
6.71
SQ
6 years, 3 months, 18 days
100
10.172
34 years
90
3.58
R0.5
22 years, 6 months
101
64.419
10 years
11.02
SQ
0 years
102
34.753
36 years
85
4.51
L0
26 years, 2 months, 12 days
103
8,178.126
104
105
45.467
34 years
10
2.59
S4
18 years, 7 months, 6 days
106
0.058
27 years
4.38
L5
13 years, 6 months
107
0.046
25 years
4.01
S5
22 years, 6 months
108
39.354
27 years
3.73
S6
18 years, 4 months, 24 days
109
0.278
26 years
2.76
L4
6 years, 8 months, 12 days
110
5.336
22 years
4.6
L3
15 years, 10 months, 24 days
111
373.821
30 years
50
4.9
R2
22 years, 6 months
112
8.197
30 years
50
4.47
R2
19 years
113
14.164
30 years
3.16
R2
22 years, 8 months, 12 days
114
2.2
30 years
50
5.13
R2
28 years, 3 months, 18 days
115
3.242
16 years
6.31
L4
9 years, 7 months, 6 days
116
492.163
117
16,752.432


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: DepreciationAndAmortization
Reclassification of 2021 Electric Depreciation and Amortization Charges Depreciation and Amortization Expense Charged in Accordance with FERC Seven Factor Test In Accordance with Guidelines in FERC Order 888

Depreciation
Expense
(Account 403)
Amortization of
Limited Term
Electric Plant
(Account 404)
Amortization
of Other
Electric Plant
(Account 405)
Total
Intangible Plant —  15,043,789  —  15,043,789 
Steam Production 25,682,223  —  —  25,682,223 
Nuclear Production —  —  —  — 
Other Production 26,108,598  —  —  26,108,598 
Transmission Plant 207,188,991  —  1,938,548  209,127,539 
Distribution Plant 321,795,786  —  2,078,582  323,874,368 
General Plant 22,351,710  —  —  22,351,710 
Common Plant-Electric 56,368,616  67,509,038  —  123,877,654 
Total Ratemaking Electric
Depreciation & Amort. (1)
659,495,924  82,552,827  4,017,130  746,065,881 

(1) Ties to Line 12 of FERC Form 1, page 336

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
REGULATORY COMMISSION EXPENSES
  1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
  2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years.
  3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
  4. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts.
  5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Line No.
RegulatoryCommissionDescription
Description (Furnish name of regulatory commission or body the docket or case number and a description of the case)
(a)
RegulatoryExpensesAssessedByRegulatoryCommission
Assessed by Regulatory Commission
(b)
RegulatoryExpensesOfUtility
Expenses of Utility
(c)
RegulatoryCommissionExpensesAmount
Total Expenses for Current Year
(d)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred in Account 182.3 at Beginning of Year
(e)
NameOfDepartmentRegulatoryCommissionExpensesCharged
Department
(f)
AccountNumberRegulatoryCommissionExpensesCharged
Account No.
(g)
RegulatoryComissionExpensesIncurredAndCharged
Amount
(h)
RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets
Deferred to Account 182.3
(i)
DeferredRegulatoryCommissionExpensesAmortizedInContraAccount
Contra Account
(j)
DeferredRegulatoryCommissionExpensesAmortized
Amount
(k)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred in Account 182.3 End of Year
(l)
1
D. 20-12-039 ENERGY STORAGE PROCUREMENT
2,693.22
2,693.22
Elec
2,693
2
D. 20-12-041 ELECTRICITY INTEGRATED RESOURCE
999.45
999.45
Elec
999
3
D. 20-12-042 RESIDENTIAL RATE DESIGN WINDOW
4,221.46
4,221.46
Elec
4,221
4
D. 20-12-043 RESIDENTIAL RATE DESIGN WINDOW
7,928.99
7,928.99
Elec
7,929
5
D. 21-02-016 INTEGRATED DISTRIBUTED ENERGY
2,484.48
2,484.48
Elec
2,484
6
D. 21-02-017 RESIDENTIAL RATE DESIGN WINDOW
15,406.44
15,406.44
Elec
15,406
7
D. 21-02-018 ENERGY EFFICIENCY ROLLING PORTFOLIO_1
483.18
483.18
Elec
483
8
D. 21-02-018 ENERGY EFFICIENCY ROLLING PORTFOLIO_2
55.92
55.92
Gas
56
9
D. 21-02-019 PIPELINE SAFETY AND RELIABILITY PROJECT
1,809.24
1,809.24
Gas
1,809
10
D. 21-02-020 BUILDING DECARBONIZATION_1
3,442.16
3,442.16
Elec
3,442
11
D. 21-02-020 BUILDING DECARBONIZATION_2
510.24
510.24
Gas
510
12
D. 21-02-021 BUILDING DECARBONIZATION _1
5,980.20
5,980.20
Elec
5,980
13
D. 21-02-021 BUILDING DECARBONIZATION_2
886.47
886.47
Gas
886
14
D. 21-02-022 BUILDING DECARBONIZATION_1
1,825.35
1,825.35
Elec
1,825
15
D. 21-02-022 BUILDING DECARBONIZATION_2
270.58
270.58
Gas
271
16
D. 21-02-023 BUILDING DECARBONIZATION _1
4,018.42
4,018.42
Elec
4,018
17
D. 21-02-023 BUILDING DECARBONIZATION_2
595.67
595.67
Gas
596
18
D. 21-02-024 BUILDING DECARBONIZATION_1
3,297.87
3,297.87
Elec
3,298
19
D. 21-02-024 BUILDING DECARBONIZATION_2
488.85
488.85
Gas
489
20
D. 21-02-025 BUILDING DECARBONIZATION_1
3,495.60
3,495.60
Elec
3,496
21
D. 21-02-025 BUILDING DECARBONIZATION_2
518.16
518.16
Gas
518
22
D. 21-02-026 ELECTRICITY INTEGRATED RESOURCE
18,866.47
18,866.47
Elec
18,866
23
D. 21-02-027 WILDFIRE EXPENSE
14,685.61
14,685.61
Elec
14,686
24
D. 21-03-011 MOBILEHOME PARK PILOT PROGRAM_1
461.22
461.22
Elec
461
25
D. 21-03-011 MOBILEHOME PARK PILOT PROGRAM_2
53.38
53.38
Gas
53
26
D. 21-03-012 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_1
1,371.09
1,371.09
Elec
1,371
27
D. 21-03-012 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_2
203.25
203.25
Gas
203
28
D. 21-03-015 RESIDENTIAL RATE STRUCTURES
3,113.73
3,113.73
Elec
3,114
29
D. 21-03-016 RESIDENTIAL RATE STRUCTURES
2,666.43
2,666.43
Elec
2,666
30
D. 21-03-031 ELECTRICITY INTEGRATED RESOURCE
1,431.24
1,431.24
Elec
1,431
31
D. 21-03-032 ENERGY EFFICIENCY ROLLING PORTFOLIO_1
5,446.76
5,446.76
Elec
5,447
32
D. 21-03-032 ENERGY EFFICIENCY ROLLING PORTFOLIO_2
807.39
807.39
Gas
807
33
D. 21-03-034 ELECTRICITY INTEGRATED RESOURCE
3,546.49
3,546.49
Elec
3,546
34
D. 21-03-036 ELECTRICITY INTEGRATED RESOURCE
6,770.40
6,770.40
Elec
6,770
35
D. 21-03-037 ELECTRICITY INTEGRATED RESOURCE
7,109.49
7,109.49
Elec
7,110
36
D. 21-03-038 ELECTRICITY INTEGRATED RESOURCE
3,991.87
3,991.87
Elec
3,992
37
D. 21-03-039 ELECTRICITY INTEGRATED RESOURCE
24,544.22
24,544.22
Elec
24,544
38
D. 21-03-040 ELECTRICITY INTEGRATED RESOURCE
21,114.52
21,114.52
Elec
21,115
39
D. 21-03-053 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_1
108.43
108.43
Elec
108
40
D. 21-03-053 ENERGY EFFICIENCY ROLLING PORTFOLIO BUSINESS PLAN_2
12.55
12.55
Gas
13
41
D. 21-04-009 WILDFIRE MITIGATION PLANS
1,108.03
1,108.03
Elec
1,108
42
D. 21-04-011 WILDFIRE MITIGATION PLANS
3,905.90
3,905.90
Elec
3,906
43
D. 21-04-012 RESIDENTIAL RATE STRUCTURES
24,028.51
24,028.51
Elec
24,029
44
D. 21-05-010 PUBLIC UTILITY REGULATORY POLICIES
1,986.00
1,986.00
Elec
1,986
45
D. 21-05-011 WILDFIRE MITIGATION PLANS
8,378.59
8,378.59
Elec
8,379
46
D. 21-05-013 WILDFIRE MITIGATION PLANS
6,381.18
6,381.18
Elec
6,381
47
D. 21-05-014 MOBILEHOME PARK PILOT PROGRAM_1
11,841.99
11,841.99
Elec
11,842
48
D. 21-05-014 MOBILEHOME PARK PILOT PROGRAM_2
1,370.45
1,370.45
Gas
1,371
49
D. 21-05-025 POWER CHARGE INDIFFERENCE
6,658.84
6,658.84
Elec
6,659
50
D. 21-05-026 ELECTRICITY INTEGRATED RESOURCE
1,610.73
1,610.73
Elec
1,611
51
D. 21-05-027 DISTRIBUTION RESOURCES PLANS
28,737.98
28,737.98
Elec
28,738
52
D. 21-05-028 RESIDENTIAL RATE DESIGN WINDOW
9,743.61
9,743.61
Elec
9,744
53
D. 21-05-029 WILDFIRE MITIGATION PLANS
67,865.23
67,865.23
Elec
67,865
54
D. 21-06-010 CALIFORNIA DISTRIBUTED GENERATION STATISTICS
1,737.50
1,737.50
Elec
1,738
55
D. 21-06-011 WILDFIRE MITIGATION PLANS
2,727.66
2,727.66
Elec
2,728
56
D. 21-07-022 ENERGY ACCESS_1
9,635.65
9,635.65
Elec
9,636
57
D. 21-07-022 ENERGY ACCESS_2
1,428.32
1,428.32
Gas
1,428
58
D. 21-07-024 ENERGY ACCESS_1
8,064.48
8,064.48
Elec
8,065
59
D. 21-07-024 ENERGY ACCESS_2
1,195.42
1,195.42
Gas
1,195
60
D. 21-07-025 ENERGY ACCESS_1
10,767.39
10,767.39
Elec
10,767
61
D. 21-07-025 ENERGY ACCESS_2
1,596.08
1,596.08
Gas
1,596
62
D. 21-07-026 DE-ENERGIZATION POWER LINES
9,941.98
9,941.98
Elec
9,942
63
D. 21-08-013 PUBLIC UTILITY REGULATORY POLICIES
10,242.03
10,242.03
Elec
10,242
64
D. 21-08-014 DE-ENERGIZATION POWER LINES
1,046.03
1,046.03
Elec
1,046
65
D. 21-08-015 AFFORABLE UTILITY SERVICE_1
7,408.78
7,408.78
Elec
7,409
66
D. 21-08-015 AFFORABLE UTILITY SERVICE_2
1,098.23
1,098.23
Gas
1,098
67
D. 21-08-016 DE-ENERGIZATION POWER LINES
3,387.58
3,387.58
Elec
3,388
68
D. 21-08-017 DE-ENERGIZATION POWER LINES
6,396.39
6,396.39
Elec
6,396
69
D. 21-08-018 DE-ENERGIZATION POWER LINES
3,139.97
3,139.97
Elec
3,140
70
D. 21-08-030 RESOURCE ADEQUACY PROGRAM
9,737.92
9,737.92
Elec
9,738
71
D. 21-08-031 DE-ENERGIZATION POWER LINES
7,415.28
7,415.28
Elec
7,415
72
D. 21-08-033 ENERGY ACCESS_1
14,739.12
14,739.12
Elec
14,739
73
D. 21-08-033 ENERGY ACCESS_2
1,705.73
1,705.73
Gas
1,706
74
D. 21-08-035 MICROGRIDS
4,811.87
4,811.87
Elec
4,812
75
D. 21-09-014 RESIDENTIAL RATES
26,805.85
26,805.85
Elec
26,806
76
D. 21-09-033 CLIMATE CHANGE ADAPTATION_1
8,565.30
8,565.30
Elec
8,565
77
D. 21-09-033 CLIMATE CHANGE ADAPTATION_2
991.25
991.25
Gas
991
78
D. 21-09-036 ELECTRIC SALES FORECAST
18,971.64
18,971.64
Elec
18,972
79
D. 21-10-007 NATURAL GAS PIPELINES
13,390.19
13,390.19
Gas
13,390
80
D. 21-10-008 WILDFIRE MITIGATION PLANS
6,781.49
6,781.49
Elec
6,782
81
D. 21-10-011 TRIENNIAL COST ALLOCATION
2,344.59
2,344.59
Gas
2,345
82
D. 21-10-028 RESOURCE ADEQUACY PROGRAM
20,845.54
20,845.54
Elec
20,846
83
D. 21-11-022 RESOURCE ADEQUACY PROGRAM
2,119.50
2,119.50
Elec
2,120
84
D. 21-11-023 RESOURCE ADEQUACY PROGRAM
14,183.55
14,183.55
Elec
14,184
85
D. 21-11-024 INTEGRATED DISTRIBUTED ENERGY RESOURCES
23,819.65
23,819.65
Elec
23,820
86
D. 21-11-025 ELECTRICITY INTEGRATED RESOURCE
10,081.07
10,081.07
Elec
10,081
87
D. 21-11-026 COST OF CAPITAL_1
15,140.26
15,140.26
Elec
15,140
88
D. 21-11-026 COST OF CAPITAL_2
2,244.29
2,244.29
Gas
2,244
89
D. 21-11-027 TRIENNIAL COST ALLOCATION
1,455.29
1,455.29
Gas
1,455
90
D. 21-12-012 WILDFIRE MITIGATION PLANS
5,139.46
5,139.46
Elec
5,140
91
D. 21-12-014 ELECTRICITY INTEGRATED RESOURCE
5,939.03
5,939.03
Elec
5,939
92
California Public Utilities Commission fees_1
22,235,548.60
22,235,548.60
Elec
22,235,549
93
California Public Utilities Commission fees_2
3,646,904.50
3,646,904.50
Gas
3,646,905
94
FERC Proceedings _1
270,233.87
270,233.87
Elec
270,234
95
FERC Proceedings_2
91,670.33
91,670.33
Gas
91,670
96
Miscellaneous_1
12,256,696.47
12,256,696.47
Elec
12,256,696
97
Miscellaneous_2
3,567,536.31
3,567,536.31
Gas
3,567,536
98
D. 20-01-016 DISTRIBUTED ENERGY & RULE 21
3,832.27
3,832.27
Elec
3,832
46
TOTAL
25,882,453.10
16,838,344.14
42,720,797.24
42,720,797


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
  1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts).
  2. Indicate in column (a) the applicable classification, as shown below:
    Classifications:
    1. Electric R, D and D Performed Internally:
      1. Generation
        1. hydroelectric
          1. Recreation fish and wildlife
          2. Other hydroelectric
        2. Fossil-fuel steam
        3. Internal combustion or gas turbine
        4. Nuclear
        5. Unconventional generation
        6. Siting and heat rejection
      2. Transmission
        1. Overhead
        2. Underground
      3. Distribution
      4. Regional Transmission and Market Operation
      5. Environment (other than equipment)
      6. Other (Classify and include items in excess of $50,000.)
      7. Total Cost Incurred
    2. Electric, R, D and D Performed Externally:
      1. Research Support to the electrical Research Council or the Electric Power Research Institute
      2. Research Support to Edison Electric Institute
      3. Research Support to Nuclear Power Groups
      4. Research Support to Others (Classify)
      5. Total Cost Incurred
  3. Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity.
  4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e).
  5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year.
  6. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est.""
  7. Report separately research and related testing facilities operated by the respondent.
AMOUNTS CHARGED IN CURRENT YEAR
Line No.
ResearchDevelopmentAndDemonstrationClassification
Classification
(a)
ResearchDevelopmentAndDemonstrationDescription
Description
(b)
ResearchDevelopmentAndDemonstrationCostsIncurredInternally
Costs Incurred Internally Current Year
(c)
ResearchDevelopmentAndDemonstrationCostsIncurredExternally
Costs Incurred Externally Current Year
(d)
AccountNumberForResearchDevelopmentAndDemonstrationCosts
Amounts Charged In Current Year: Account
(e)
ResearchDevelopmentAndDemonstrationCosts
Amounts Charged In Current Year: Amount
(f)
ResearchDevelopmentAndDemonstrationExpenditures
Unamortized Accumulation
(g)
1
A. Electric R, D & D Performed Internally
2
(1) Generation
NONE
3
(2) System Planning, Engineering and Operation
NONE
4
(3) Transmission
NONE
5
(4) Distribution
RD&D Performed Internally
4,996,641
4,996,641
6
35,314
35,314
7
(5) Environment
NONE
8
(6) Other
NONE
9
(7) Sub Total Internal Costs Incurred
5,031,955
5,031,955
10
B. External
11
(1) Research Support to the Electrical
NONE
12
Research Council or the Electrical Power
NONE
13
Research Institute
NONE
14
(2) Research Support to Edison Electric Inst.
NONE
15
(3) Research Support to Nuclear Power Groups
NONE
16
(4) Research Support to Others
CPUC and California Energy Commission
18,822,643
18,822,643
17
(5) Sub Total External Costs Incurred
18,822,643
18,822,643


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
DISTRIBUTION OF SALARIES AND WAGES

Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.

Line No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for Clearing Accounts
(c)
Total
(d)
1
SalariesAndWagesElectricAbstract
Electric
2
SalariesAndWagesElectricOperationAbstract
Operation
3
SalariesAndWagesElectricOperationProduction
Production
10,228,064
4
SalariesAndWagesElectricOperationTransmission
Transmission
15,537,615
5
SalariesAndWagesElectricOperationRegionalMarket
Regional Market
6
SalariesAndWagesElectricOperationDistribution
Distribution
45,868,701
7
SalariesAndWagesElectricOperationCustomerAccounts
Customer Accounts
17,729,049
8
SalariesAndWagesElectricOperationCustomerServiceAndInformational
Customer Service and Informational
17,269,345
9
SalariesAndWagesElectricOperationSales
Sales
10
SalariesAndWagesElectricOperationAdministrativeAndGeneral
Administrative and General
52,377,243
11
SalariesAndWagesElectricOperation
TOTAL Operation (Enter Total of lines 3 thru 10)
159,010,017
12
SalariesAndWagesElectricMaintenanceAbstract
Maintenance
13
SalariesAndWagesElectricMaintenanceProduction
Production
2,123,124
14
SalariesAndWagesElectricMaintenanceTransmission
Transmission
13,157,040
15
SalariesAndWagesElectricMaintenanceRegionalMarket
Regional Market
16
SalariesAndWagesElectricMaintenanceDistribution
Distribution
19,930,291
17
SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral
Administrative and General
1,459,234
18
SalariesAndWagesElectricMaintenance
TOTAL Maintenance (Total of lines 13 thru 17)
36,669,689
19
SalariesAndWagesElectricOperationAndMaintenanceAbstract
Total Operation and Maintenance
20
SalariesAndWagesElectricProduction
Production (Enter Total of lines 3 and 13)
12,351,188
21
SalariesAndWagesElectricTransmission
Transmission (Enter Total of lines 4 and 14)
28,694,655
22
SalariesAndWagesElectricRegionalMarket
Regional Market (Enter Total of Lines 5 and 15)
23
SalariesAndWagesElectricDistribution
Distribution (Enter Total of lines 6 and 16)
65,798,992
24
SalariesAndWagesElectricCustomerAccounts
Customer Accounts (Transcribe from line 7)
17,729,049
25
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational (Transcribe from line 8)
17,269,345
26
SalariesAndWagesElectricSales
Sales (Transcribe from line 9)
27
SalariesAndWagesElectricAdministrativeAndGeneral
Administrative and General (Enter Total of lines 10 and 17)
53,836,477
28
SalariesAndWagesElectricOperationAndMaintenance
TOTAL Oper. and Maint. (Total of lines 20 thru 27)
195,679,706
48,262,727
243,942,433
29
SalariesAndWagesGasAbstract
Gas
30
SalariesAndWagesGasOperationAbstract
Operation
31
SalariesAndWagesGasOperationProductionManufacturedGas
Production - Manufactured Gas
32
SalariesAndWagesGasOperationProductionNaturalGas
Production-Nat. Gas (Including Expl. And Dev.)
33
SalariesAndWagesGasOperationOtherGasSupply
Other Gas Supply
34
SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing
Storage, LNG Terminaling and Processing
168,162
35
SalariesAndWagesGasOperationTransmission
Transmission
2,828,984
36
SalariesAndWagesGasOperationDistribution
Distribution
29,075,577
37
SalariesAndWagesGasCustomerAccounts
Customer Accounts
8,758,536
38
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational
2,203,151
39
SalariesAndWagesGasSales
Sales
40
SalariesAndWagesGasOperationAdministrativeAndGeneral
Administrative and General
17,076,523
41
SalariesAndWagesGasOperation
TOTAL Operation (Enter Total of lines 31 thru 40)
60,110,933
42
SalariesAndWagesGasMaintenanceAbstract
Maintenance
43
SalariesAndWagesGasMaintenanceProductionManufacturedGas
Production - Manufactured Gas
44
SalariesAndWagesGasMaintenanceProductionNaturalGas
Production-Natural Gas (Including Exploration and Development)
45
SalariesAndWagesGasMaintenanceOtherGasSupply
Other Gas Supply
46
SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing
47
SalariesAndWagesGasMaintenanceTransmission
Transmission
1,207,516
48
SalariesAndWagesGasMaintenanceDistribution
Distribution
7,762,257
49
SalariesAndWagesGasMaintenanceAdministrativeAndGeneral
Administrative and General
579,316
50
SalariesAndWagesGasMaintenance
TOTAL Maint. (Enter Total of lines 43 thru 49)
9,549,089
51
SalariesAndWagesGasOperationAndMaintenanceAbstract
Total Operation and Maintenance
52
SalariesAndWagesGasProductionManufacturedGas
Production-Manufactured Gas (Enter Total of lines 31 and 43)
53
SalariesAndWagesGasProductionNaturalGas
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54
SalariesAndWagesGasOtherGasSupply
Other Gas Supply (Enter Total of lines 33 and 45)
55
SalariesAndWagesGasStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing (Total of lines 31 thru
168,162
56
SalariesAndWagesGasTransmission
Transmission (Lines 35 and 47)
4,036,500
57
SalariesAndWagesGasDistribution
Distribution (Lines 36 and 48)
36,837,834
58
SalariesAndWagesGasCustomerAccounts
Customer Accounts (Line 37)
8,758,536
59
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational (Line 38)
2,203,151
60
SalariesAndWagesGasSales
Sales (Line 39)
61
SalariesAndWagesGasAdministrativeAndGeneral
Administrative and General (Lines 40 and 49)
17,655,839
62
SalariesAndWagesGasOperationAndMaintenance
TOTAL Operation and Maint. (Total of lines 52 thru 61)
69,660,022
16,647,370
86,307,392
63
SalariesAndWagesOtherUtilityDepartmentsAbstract
Other Utility Departments
64
SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance
Operation and Maintenance
65
SalariesAndWagesOperationsAndMaintenance
TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
265,339,728
64,910,097
330,249,825
66
SalariesAndWagesUtilityPlantAbstract
Utility Plant
67
SalariesAndWagesUtilityPlantConstructionAbstract
Construction (By Utility Departments)
68
SalariesAndWagesUtilityPlantConstructionElectricPlant
Electric Plant
84,994,108
154,554,801
239,548,909
69
SalariesAndWagesUtilityPlantConstructionGasPlant
Gas Plant
21,622,166
34,994,705
56,616,871
70
SalariesAndWagesUtilityPlantConstructionOther
Other (provide details in footnote):
71
SalariesAndWagesUtilityPlantConstruction
TOTAL Construction (Total of lines 68 thru 70)
106,616,274
189,549,506
296,165,780
72
SalariesAndWagesPlantRemovalAbstract
Plant Removal (By Utility Departments)
73
SalariesAndWagesPlantRemovalElectricPlant
Electric Plant
7,619,504
13,782,759
21,402,263
74
SalariesAndWagesPlantRemovalGasPlant
Gas Plant
1,463,390
1,503,610
2,967,000
75
SalariesAndWagesPlantRemovalOther
Other (provide details in footnote):
76
SalariesAndWagesPlantRemoval
TOTAL Plant Removal (Total of lines 73 thru 75)
9,082,894
15,286,369
24,369,263
77
SalariesAndWagesOtherAccountsAbstract
Other Accounts (Specify, provide details in footnote):
78
SalariesAndWagesOtherAccountsDescription
Other Accounts (Specify, provide details in footnote):
79
SalariesAndWagesOtherAccountsDescription
3rd Party Billings, Gas
1,579,775
898,658
2,478,433
80
SalariesAndWagesOtherAccountsDescription
3rd Party Billings, Electric
5,098,018
2,942,800
8,040,818
81
SalariesAndWagesOtherAccountsDescription
Affiliate Billings, Gas
10,299,792
10,299,792
82
SalariesAndWagesOtherAccountsDescription
Affiliate Billings, Electric
30,362,631
30,362,631
83
SalariesAndWagesOtherAccountsDescription
84
SalariesAndWagesOtherAccountsDescription
85
SalariesAndWagesOtherAccountsDescription
86
SalariesAndWagesOtherAccountsDescription
87
SalariesAndWagesOtherAccountsDescription
88
SalariesAndWagesOtherAccountsDescription
89
SalariesAndWagesOtherAccountsDescription
90
SalariesAndWagesOtherAccountsDescription
91
SalariesAndWagesOtherAccountsDescription
92
SalariesAndWagesOtherAccountsDescription
93
SalariesAndWagesOtherAccountsDescription
94
SalariesAndWagesOtherAccountsDescription
95
SalariesAndWagesOtherAccounts
TOTAL Other Accounts
6,677,793
44,503,881
51,181,674
96
SalariesAndWagesGeneralExpense
TOTAL SALARIES AND WAGES
387,716,689
314,249,853
(a)
701,966,542


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: SalariesAndWagesGeneralExpense
FERC accounts 417 and 426 are not included in the detail classification lines or summary totals.
FERC 417 for 2021 amounts to $3,110,104
FERC 426 for 2021 amounts to $1,280,345

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
COMMON UTILITY PLANT AND EXPENSES
  1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Electric Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
  2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.
  3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation.
  4. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.
AccountBalance Beg.
of Year
AdditionsRetire
From Serv.
Adjs.TransfersBalance End
of Year
303 Misc. Intangible Plant685,051,572 345,014,337 124,598,184 (160,597)905,307,128 
389 Land & Land Rights7,522,569 7,522,573 
390 Structures & Improvs.508,494,134 54,341,094 (269,669)118,133 562,683,692 
391 Office Furn. & Equip.146,758,601 28,108,325 11,716,842 (52,005)163,098,079 
392 Transportation Equip.12,515,872 137,812 (166)12,653,518 
393 Stores Equipment333,836 (853)332,983 
394 Tools, Shop & Garage Eq.3,501,263 636 (24)3,500,603 
395 Laboratory Equipment1,731,117 (22)1,731,095 
396 Power Equipment
397 Communication Eq.306,074,404 57,023,426 9,144,218 (76,418)353,877,194 
398 Misc. Equipment3,587,315 343 (2,595)3,585,063 
FIN 47 ARC-Common7,167,302 (1,661,903)5,505,399 
Fleet Capital Leases91,311,488 22,054,277 2,880,443 110,485,322 
Other Capital Leases118,014,626 8,396,037 126,410,663 
TOTAL COMMON PLANT1,892,064,099 515,075,651 148,340,323 (2,224,248)118,133 2,256,693,312 
Construction Work in Prog.418,262,973 (60,924,537)357,338,436 
TOTAL COMMON PLANT2,310,327,072 454,151,114 148,340,323 (2,224,248)118,133 2,614,031,748 
December 31, 2021
ACCOUNTAccumulated Depreciation
303 Misc. Intangible Plant449,430,696
389 Land & Land Rights27,776
390 Structures and Improvements195,013,888
391 Office Furniture & Equipment74,918,490
392 Transportation Equipment4,940,975
393 Stores Equipment72,500
394 Tools, Shop, & Garage Equipment1,449,949
395 Laboratory Equipment1,017,411
396 Power Operated Equipment(192,979)
397 Communication Equipment130,419,384
398 Miscellaneous Equipment833,853
108.4 Retirement Work in Progress0
FIN 47 Accumulated Depreciation2,922,489
Fleet Capital Lease44,534,499
Other Capital Lease56,569,524
 
Total Accumulated Depreciation961,958,455

Split of Common Utility Plant
to Departments: (excluding CWIP)
December 31, 2021
Balance
End of Year
Accumulated
Depreciation
Electric74.67 %1,685,072,898 718,294,379 
Gas25.33 %571,620,417 243,664,077 
TOTAL100.00 %2,256,693,315 961,958,456 
Ad Valorem
Taxes
Depreciation
Note (1)Note (2)
ACCOUNT
303 Misc. Intangible Plant90,409,855 
389 Land and Land Rights— 
390 Structures & Improvements19,146,506 
391 Office Furniture & Equipment29,293,321 
392 Transportation Equipment1,176,142 
393 Stores Equipment16,487 
394 Portable Tools182,263 
395 Laboratory Equipment76,165 
396 Power Operated Equipment— 
397 Communication Equipment25,361,203 
398 Miscellaneous Equipment238,225 
TOTAL165,900,167 

(1)Ad Valorem Taxes on property are assessed by the State Board of Equalization and consist of one-half of the taxes from each fiscal tax year 2020-2021 and 2021-2022. Ad Valorem Taxes are assessed on the entire operating unit, therefore, assessed taxes are not available by account number. Ad Valorem Taxes are allocated based on procedures adopted by the California Public Utilities Commission.
(2)The Common Utility Plant and Accumulated Depreciation is allocated between the Electric and Gas Departments based on labor ratios in accordance with allocation procedures adopted by the California Public Utilities Commission. These rates were revised in January 2021.
Other expenses of operation, maintenance and rents for common utility plant are allocated based on labor percentage studies. Specific amounts charged to operations and maintenance are not readily available.


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
  1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.
Description of Item(s)
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1 Energy
2 Net Purchases (Account 555)
144,278,874
279,336,249
527,201,265
706,304,175
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)
70,625,074
139,830,057
374,148,439
501,451,465
4 Transmission Rights
5 Ancillary Services
953,348
1,791,408
1,968,125
1,341,092
6 Other Items (list separately)
7
Congestion
1,840,959
3,531,344
6,671,971
7,236,270
8
CRR (Congestion Revenue Rights)
4,741,526
8,396,144
12,897,017
19,285,963
9
GMC (Grid Management Charges)
1,572,767
3,547,137
5,873,902
7,571,934
10
Other
1,034,948
56,723
1,080,822
135,928
11
UFE (Unaccounted for Energy)
3,101,454
682,735
1,413,415
6,607,198
46 TOTAL
75,345,854
140,605,949
154,337,214
195,244,773


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
  1. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year.
  2. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year.
  3. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year.
  4. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year.
  5. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period.
  6. On Line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Line No.
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of Measure
(c)
Dollar
(d)
Number of Units
(e)
Unit of Measure
(f)
Dollars
(g)
1
Scheduling, System Control and Dispatch
1,339,669
MWH
10,318,211
1,502,316
MWH
8,977,120
2
Reactive Supply and Voltage
3
Regulation and Frequency Response
4
Energy Imbalance
5
Operating Reserve - Spinning
6
Operating Reserve - Supplement
7
Other
8
Total (Lines 1 thru 7)
1,339,669
10,318,211
1,502,316
8,977,120


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
  1. Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Firm Network Service for Self
(e)
Firm Network Service for Others
(f)
Long-Term Firm Point-to-point Reservations
(g)
Other Long-Term Firm Service
(h)
Short-Term Firm Point-to-point Reservation
(i)
Other Service
(j)
NAME OF SYSTEM: 0
1
January
3,065
25
18
3,065
2
February
2,792
9
18
2,792
3
March
2,861
3
18
2,861
4
Total for Quarter 1
8,718
0
0
0
5
April
2,828
30
17
2,828
6
May
2,730
25
18
2,730
7
June
3,524
15
17
3,524
8
Total for Quarter 2
9,082
0
0
0
9
July
3,519
20
17
3,519
10
August
3,860
26
16
3,860
11
September
3,826
9
16
3,826
12
Total for Quarter 3
11,205
0
0
0
13
October
3,178
3
17
3,178
14
November
3,075
12
16
3,075
15
December
3,112
16
18
3,112
16
Total for Quarter 4
9,365
0
0
0
17
Total
38,370
0
0
0
0
0


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Monthly ISO/RTO Transmission System Peak Load
  1. Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f).
  5. Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Import into ISO/RTO
(e)
Exports from ISO/RTO
(f)
Through and Out Service
(g)
Network Service Usage
(h)
Point-to-Point Service Usage
(i)
Total Usage
(j)
NAME OF SYSTEM: 0
1
January
2
February
3
March
4
Total for Quarter 1
0
0
0
0
0
0
5
April
6
May
7
June
8
Total for Quarter 2
0
0
0
0
0
0
9
July
10
August
11
September
12
Total for Quarter 3
0
0
0
0
0
0
13
October
14
November
15
December
16
Total for Quarter 4
0
0
0
0
0
0
17
Total Year to Date/Year
0
0
0
0
0
0


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2022-04-15
Year/Period of Report

End of:
2021
/
Q4
ELECTRIC ENERGY ACCOUNT

Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

Line No. Item
(a)
MegaWatt Hours
(b)
Line No. Item
(a)
MegaWatt Hours
(b)
1
SOURCES OF ENERGY
21
DISPOSITION OF ENERGY
2
Generation (Excluding Station Use):
22
Sales to Ultimate Consumers (Including Interdepartmental Sales)
11,298,500
3
Steam
2,835,684
23
Requirements Sales for Resale (See instruction 4, page 311.)
4
Nuclear
24
Non-Requirements Sales for Resale (See instruction 4, page 311.)
9,195,146
5
Hydro-Conventional
25
Energy Furnished Without Charge
6
Hydro-Pumped Storage
47,969
26
Energy Used by the Company (Electric Dept Only, Excluding Station Use)
59,413
7
Other
20,137
27
Total Energy Losses
354,640
8
Less Energy for Pumping
62,165
27.1
Total Energy Stored
9
Net Generation (Enter Total of lines 3 through 8)
2,841,625
28
TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES
20,907,699
10
Purchases (other than for Energy Storage)
18,066,074
10.1
Purchases for Energy Storage
0
11
Power Exchanges:
12
Received
1,192,312
13
Delivered
1,192,312
14
Net Exchanges (Line 12 minus line 13)
0
15
Transmission For Other (Wheeling)
16
Received
17
Delivered
18
Net Transmission for Other (Line 16 minus line 17)
0
19
Transmission By Others Losses
20
TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)
20,907,699


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
MONTHLY PEAKS AND OUTPUT
  1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system.
  2. Report in column (b) by month the system’s output in Megawatt hours for each month.
  3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
  4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
  5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.
MonthAxis
Month
(a)
EnergyActivity
Total Monthly Energy
(b)
NonRequiredSalesForResaleEnergy
Monthly Non-Requirement Sales for Resale & Associated Losses
(c)
MonthlyPeakLoad
Monthly Peak - Megawatts
(d)
DayOfMonthlyPeak
Monthly Peak - Day of Month
(e)
HourOfMonthlyPeak
Monthly Peak - Hour
(f)
NAME OF SYSTEM: 0
29
January
1,190,990
416,403
3,065
25
18
30
February
1,093,087
503,003
2,792
9
18
31
March
1,005,091
654,770
2,861
3
18
32
April
888,357
760,224
2,828
30
17
33
May
915,669
666,242
2,730
25
18
34
June
1,029,334
797,466
3,524
15
17
35
July
894,407
906,929
3,519
20
17
36
August
889,647
1,472,270
3,860
26
16
37
September
1,005,458
893,348
3,826
9
16
38
October
793,474
669,977
3,178
3
17
39
November
764,564
691,374
3,075
12
16
40
December
828,422
763,140
3,112
16
18
41
Total
11,298,500
9,195,146


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on USofA accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.
Item
(a)
Plant Name:
Cuyamaca
Plant Name:
Desert Star
Plant Name:
Miramar
Plant Name:
Palomar
1
PlantKind
Kind of Plant (Internal Comb, Gas Turb, Nuclear)
Gas Turbine
Combined Cycle
Gas Turbine (2)
Combined Cycle
2
PlantConstructionType
Type of Constr (Conventional, Outdoor, Boiler, etc)
Semi-Outdoor
Semi-Outdoor
Semi-Outdoor
Semi-Outdoor
3
YearPlantOriginallyConstructed
Year Originally Constructed
2002
2000
2005
2006
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
2002
2000
2009
2006
5
InstalledCapacityOfPlant
Total Installed Cap (Max Gen Name Plate Ratings-MW)
47
536
96
588
6
NetPeakDemandOnPlant
Net Peak Demand on Plant - MW (60 minutes)
47
485
96
588
7
PlantHoursConnectedToLoad
Plant Hours Connected to Load
481
8,760
435
4,815
8
NetContinuousPlantCapability
Net Continuous Plant Capability (Megawatts)
47
450
96
588
9
NetContinuousPlantCapabilityNotLimitedByCondenserWater
When Not Limited by Condenser Water
47
450
96
588
10
NetContinuousPlantCapabilityLimitedByCondenserWater
When Limited by Condenser Water
47
450
96
0
11
PlantAverageNumberOfEmployees
Average Number of Employees
1
23
3
32
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - kWh
8,182,000
1,000,359,308
20,180,000
1,833,691,000
13
CostOfLandAndLandRightsSteamProduction
Cost of Plant: Land and Land Rights
14,480,000
14
CostOfStructuresAndImprovementsSteamProduction
Structures and Improvements
1,897,458
32,654,564
5,075,863
79,334,067
15
CostOfEquipmentSteamProduction
Equipment Costs
30,500,752
314,306,477
106,413,303
518,543,801
16
AssetRetirementCostsSteamProduction
Asset Retirement Costs
1,955,311
17
CostOfPlant
Total cost (total 13 thru 20)
32,398,210
348,916,352
111,489,166
612,357,868
18
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 17/5) Including
689.3236
650.9633
1,161.3455
1,041.4249
19
OperationSupervisionAndEngineeringExpense
Production Expenses: Oper, Supv, & Engr
1,750
719,844
4,073
1,454,949
20
FuelSteamPowerGeneration
Fuel
894,996
44,258,740
1,488,814
95,242,721
21
CoolantsAndWater
Coolants and Water (Nuclear Plants Only)
22
SteamExpensesSteamPowerGeneration
Steam Expenses
7,494
2,112,465
6,999
4,103,433
23
SteamFromOtherSources
Steam From Other Sources
24
SteamTransferredCredit
Steam Transferred (Cr)
934
25
ElectricExpensesSteamPowerGeneration
Electric Expenses
278,410
1,381,502
291,783
2,757,396
26
MiscellaneousSteamPowerExpenses
Misc Steam (or Nuclear) Power Expenses
27
RentsSteamPowerGeneration
Rents
306
28
Allowances
Allowances
29
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
Maintenance Supervision and Engineering
30
MaintenanceOfStructuresSteamPowerGeneration
Maintenance of Structures
13,158
82,914
31
MaintenanceOfBoilerPlantSteamPowerGeneration
Maintenance of Boiler (or reactor) Plant
2,282,573
795,759
32
MaintenanceOfElectricPlantSteamPowerGeneration
Maintenance of Electric Plant
921,377
7,468,600
1,852,599
5,314,835
33
MaintenanceOfMiscellaneousSteamPlant
Maintenance of Misc Steam (or Nuclear) Plant
751
1,180,570
2,749
6,601,633
34
PowerProductionExpensesSteamPower
Total Production Expenses
2,117,936
59,404,294
3,647,017
116,189,052
35
ExpensesPerNetKilowattHour
Expenses per Net kWh
0.2589
0.0593
0.1807
0.0634
35
FuelKindAxis
Plant Name
Cuyamaca
Desert Star
Miramar
Palomar
36
FuelKind
Fuel Kind
GAS
GAS
GAS
GAS
37
FuelUnit
Fuel Unit
Mcf
Mcf
Mcf
Mcf
38
QuantityOfFuelBurned
Quantity (Units) of Fuel Burned
92,315
7,407,765
201,966
12,700,404
39
FuelBurnedAverageHeatContent
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0
0
40
AverageCostOfFuelPerUnitAsDelivered
Avg Cost of Fuel/unit, as Delvd f.o.b. during year
41
AverageCostOfFuelPerUnitBurned
Average Cost of Fuel per Unit Burned
9.695
5.975
7.372
7.499
42
AverageCostOfFuelBurnedPerMillionBritishThermalUnit
Average Cost of Fuel Burned per Million BTU
9.486
5.846
7.213
7.338
43
AverageCostOfFuelBurnedPerKilowattHourNetGeneration
Average Cost of Fuel Burned per kWh Net Gen
0.109
0.045
0.074
0.052
44
AverageBritishThermalUnitPerKilowattHourNetGeneration
Average BTU per kWh Net Generation
11,587.000
7,657.000
10,278.000
7,113.000


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Hydroelectric Generating Plant Statistics
  1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
  2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
  3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
  4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
  5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
  6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Line No.
Item
(a)
FERC Licensed Project No.
0
Plant Name:
0
1
PlantKind
Kind of Plant (Run-of-River or Storage)
2
PlantConstructionType
Plant Construction type (Conventional or Outdoor)
3
YearPlantOriginallyConstructed
Year Originally Constructed
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
5
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
6
NetPeakDemandOnPlant
Net Peak Demand on Plant-Megawatts (60 minutes)
7
PlantHoursConnectedToLoad
Plant Hours Connect to Load
8
NetPlantCapabilityAbstract
Net Plant Capability (in megawatts)
9
NetPlantCapabilityUnderMostFavorableOperatingConditions
(a) Under Most Favorable Oper Conditions
10
NetPlantCapabilityUnderMostAdverseOperatingConditions
(b) Under the Most Adverse Oper Conditions
11
PlantAverageNumberOfEmployees
Average Number of Employees
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - kWh
13
CostOfPlantAbstract
Cost of Plant
14
CostOfLandAndLandRightsHydroelectricProduction
Land and Land Rights
15
CostOfStructuresAndImprovementsHydroelectricProduction
Structures and Improvements
16
CostOfReservoirsDamsAndWaterwaysHydroelectricProduction
Reservoirs, Dams, and Waterways
17
EquipmentCostsHydroelectricProduction
Equipment Costs
18
CostOfRoadsRailroadsAndBridgesHydroelectricProduction
Roads, Railroads, and Bridges
19
AssetRetirementCostsHydroelectricProduction
Asset Retirement Costs
20
CostOfPlant
Total cost (total 13 thru 20)
21
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 20 / 5)
22
ProductionExpensesAbstract
Production Expenses
23
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
24
WaterForPower
Water for Power
25
HydraulicExpenses
Hydraulic Expenses
26
ElectricExpensesHydraulicPowerGeneration
Electric Expenses
27
MiscellaneousHydraulicPowerGenerationExpenses
Misc Hydraulic Power Generation Expenses
28
RentsHydraulicPowerGeneration
Rents
29
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
Maintenance Supervision and Engineering
30
MaintenanceOfStructuresHydraulicPowerGeneration
Maintenance of Structures
31
MaintenanceOfReservoirsDamsAndWaterways
Maintenance of Reservoirs, Dams, and Waterways
32
MaintenanceOfElectricPlantHydraulicPowerGeneration
Maintenance of Electric Plant
33
MaintenanceOfMiscellaneousHydraulicPlant
Maintenance of Misc Hydraulic Plant
34
PowerProductionExpensesHydraulicPower
Total Production Expenses (total 23 thru 33)
35
ExpensesPerNetKilowattHour
Expenses per net kWh


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
Pumped Storage Generating Plant Statistics
  1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings).
  2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number.
  3. If net peak demand for 60 minutes is not available, give that which is available, specifying period.
  4. If a group of employees attends more than one generating plant, report on Line 8 the approximate average number of employees assignable to each plant.
  5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
  6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.
  7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.
Item
(a)
FERC Licensed Project No.
0
Plant Name:
0
1
PlantConstructionType
Type of Plant Construction (Conventional or Outdoor)
2
YearPlantOriginallyConstructed
Year Originally Constructed
3
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
4
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
5
NetPeakDemandOnPlant
Net Peak Demaind on Plant-Megawatts (60 minutes)
0
6
PlantHoursConnectedToLoad
Plant Hours Connect to Load While Generating
0
7
NetContinuousPlantCapability
Net Plant Capability (in megawatts)
0
8
PlantAverageNumberOfEmployees
Average Number of Employees
9
NetGenerationExcludingPlantUse
Generation, Exclusive of Plant Use - kWh
0
10
EnergyUsedForPumping
Energy Used for Pumping
11
NetOutputForLoad
Net Output for Load (line 9 - line 10) - Kwh
0
12
CostOfPlantAbstract
Cost of Plant
13
CostOfLandAndLandRightsPumpedStoragePlant
Land and Land Rights
14
CostOfStructuresAndImprovementsPumpedStoragePlant
Structures and Improvements
0
15
CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Reservoirs, Dams, and Waterways
0
16
CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant
Water Wheels, Turbines, and Generators
0
17
CostOfAccessoryElectricEquipmentPumpedStoragePlant
Accessory Electric Equipment
0
18
CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant
Miscellaneous Powerplant Equipment
0
19
CostOfRoadsRailroadsAndBridgesPumpedStoragePlant
Roads, Railroads, and Bridges
0
20
AssetRetirementCostsPumpedStoragePlant
Asset Retirement Costs
0
21
CostOfPlant
Total cost (total 13 thru 20)
22
CostPerKilowattOfInstalledCapacity
Cost per KW of installed cap (line 21 / 4)
23
ProductionExpensesAbstract
Production Expenses
24
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
0
25
WaterForPower
Water for Power
0
26
PumpedStorageExpenses
Pumped Storage Expenses
0
27
ElectricExpensesPumpedStoragePlant
Electric Expenses
0
28
MiscellaneousPumpedStoragePowerGenerationExpenses
Misc Pumped Storage Power generation Expenses
0
29
RentsPumpedStoragePlant
Rents
0
30
MaintenanceSupervisionAndEngineeringPumpedStoragePlant
Maintenance Supervision and Engineering
0
31
MaintenanceOfStructuresPumpedStoragePlant
Maintenance of Structures
0
32
MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Maintenance of Reservoirs, Dams, and Waterways
0
33
MaintenanceOfElectricPlantPumpedStoragePlant
Maintenance of Electric Plant
0
34
MaintenanceOfMiscellaneousPumpedStoragePlant
Maintenance of Misc Pumped Storage Plant
0
35
PowerProductionExpenseBeforePumpingExpenses
Production Exp Before Pumping Exp (24 thru 34)
36
PumpingExpenses
Pumping Expenses
37
PowerProductionExpensesPumpedStoragePlant
Total Production Exp (total 35 and 36)
38
ExpensesPerNetKilowattHour
Expenses per kWh (line 37 / 9)
39
ExpensesPerNetKilowattHourGenerationAndPumping
Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))
0


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
GENERATING PLANT STATISTICS (Small Plants)
  1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating).
  2. Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote.
  3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402.
  4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.
  5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Production Expenses
Line No.
PlantName
Name of Plant
(a)
YearPlantOriginallyConstructed
Year Orig. Const.
(b)
InstalledCapacityOfPlant
Installed Capacity Name Plate Rating (MW)
(c)
NetPeakDemandOnPlant
Net Peak Demand MW (60 min)
(d)
NetGenerationExcludingPlantUse
Net Generation Excluding Plant Use
(e)
CostOfPlant
Cost of Plant
(f)
PlantCostPerMw
Plant Cost (Incl Asset Retire. Costs) Per MW
(g)
OperatingExpensesExcludingFuel
Operation Exc'l. Fuel
(h)
FuelProductionExpenses
Fuel Production Expenses
(i)
MaintenanceProductionExpenses
Maintenance Production Expenses
(j)
FuelKind
Kind of Fuel
(k)
FuelCostPerMmbtus
Fuel Costs (in cents (per Million Btu)
(l)
GenerationType
Generation Type
(m)
1
J&D Labs Fuel Cell
2012
0.40
3,305,506
7,505,525


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
ENERGY STORAGE OPERATIONS (Large Plants)
  1. Large Plants are plants of 10,000 Kw or more.
  2. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location.
  3. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage.
  4. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services.
  5. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy.
  6. In column (k) report the MWHs sold.
  7. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity.
  8. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power.
  9. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.
Name of the Energy Storage Project
(a)
Functional Classification
(b)
Location of the Project
(c)
MWHs
(d)
MWHs delivered to the grid to support Production
(e)
MWHs delivered to the grid to support Transmission
(f)
MWHs delivered to the grid to support Distribution
(g)
MWHs Lost During Conversion, Storage and Discharge of Energy Production
(h)
MWHs Lost During Conversion, Storage and Discharge of Energy Transmission
(i)
MWHs Lost During Conversion, Storage and Discharge of Energy Distribution
(j)
MWHs Sold
(k)
Revenues from Energy Storage Operations
(l)
Power Purchased for Storage Operations (555.1) (Dollars)
(m)
Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars)
(n)
Other Costs Associated with Self-Generated Power (Dollars)
(o)
Project Costs included in
(p)
Production (Dollars)
(q)
Transmission (Dollars)
(r)
Distribution (Dollars)
(s)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
TRANSMISSION LINE STATISTICS
  1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts.
  2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page.
  3. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
  4. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line.
  5. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.
  6. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g).
  7. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company.
  8. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company.
  9. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
DESIGNATION VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase) LENGTH (Pole miles) - (In the case of underground lines report circuit miles) COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.
TransmissionLineStartPoint
From
TransmissionLineEndPoint
To
OperatingVoltageOfTransmissionLine
Operating
DesignedVoltageOfTransmissionLine
Designated
SupportingStructureOfTransmissionLineType
Type of Supporting Structure
LengthForStandAloneTransmissionLines
On Structure of Line Designated
LengthForTransmissionLinesAggregatedWithOtherStructures
On Structures of Another Line
NumberOfTransmissionCircuits
Number of Circuits
SizeOfConductorAndMaterial
Size of Conductor and Material
CostOfLandAndLandRightsTransmissionLines
Land
ConstructionAndOtherCostsTransmissionLines
Construction Costs
OverallCostOfTransmissionLine
Total Costs
OperatingExpensesOfTransmissionLine
Operation Expenses
MaintenanceExpensesOfTransmissionLine
Maintenance Expenses
RentExpensesOfTransmissionLine
Rents
OverallExpensesOfTransmissionLine
Total Expenses
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
1
Miguel
East County
500
500
54.00
1
2-2156 ACSR
2
Imperial Valley
North Gila
500
500
(a)
79.00
1
2-2156 ACSR
3
North Gila
Palo Verde
500
500
(b)
114.00
1
2-2156 ACSR
4
Suncrest
Ocotillo Switchyard
500
500
(c)
67.00
1
3-1033.5 ACSR
5
East County
Imperial Valley
500
500
31.00
1
2-2156 ACSR
6
Octillo Switchyard
Imperial Valley
500
500
22.00
13
1
3-1033.5 ACSR
7
Octillo Switchyard
Ocotillo Express Sub
500
500
0.00
1
2-1590  ACSR
8
San Luis Rey
Mission
230
230
30
2
1-1033.5 ACSR/AW
9
230
230
4.26
1
1-1033.5 ACSR/AW
10
Mission
230
230
0
2
1-5000 KCMIL CU ENAMEL
11
San Onofre
230
230
0
5
2-1033.5 ACSR/AW
12
_1
230
230
17
2
2-1033.5 ACSR/AW
13
San Luis Rey
230
230
0.75
1
2-1033.5 ACSR/AW
14
San Luis Rey
230
230
6
2
2-1033.5 ACSR/AW
15
Encina
230
230
1
2
2-1109 ACAR
16
San Luis Rey
San Luis Rey
230
230
4.26
1
1-1033.5 ACSR/AW
17
_2
230
230
30
2
1-1033.5 ACSR/AW
18
Mission_2
230
230
0
2
1-5000 KCMIL CU ENAMEL
19
San Luis Rey
230
230
17.61
1
1-1033.5 ACSR/AW
20
230
230
0
2
1-1033.5 ACSR/AW
21
San Onofre
230
230
0
5
2-1033.5 ACSR/AW
22
San Onofre_1
230
230
6
2
1-1033.5 ACSR/AW
23
230
230
1
5
2-1033.5 ACSR/AW
24
Talega
230
230
0.11
1
2-1033.5 ACSR/AW
25
San Onofre_2
230
230
1.00
1
2-1033.5 ACSR/AW
26
230
230
0
5
2-1033.5 ACSR/AW
27
San Luis Rey
230
230
17
2
2-1033.5 ACSR/AW
28
San Luis Rey_2
230
230
6
2
2-1033.5 ACSR/AW
29
_1
230
230
2
2
2-1109 ACAR
30
230
230
7
2
2-1109 ACAR
31
230
230
5
2
2-1109 ACAR
32
230
230
1
2
2-900 ACSS/AW
33
Palomar Energy
230
230
0.26
1
2-1109 ACAR
34
Encina
230
230
18
2
2-1109 ACAR
35
Penasquitos
230
230
0
2
2-1033.5 ACSR/AW
36
Penasquitos
230
230
2
2
2-1033.5 ACSR/AW
37
Old Town
230
230
7.19
1
2-1109 ACAR
38
Palomar_1
230
230
0
2
2-900 ACSS/AW
39
Old Town
230
230
0
2
2-605 ACSS/AW
40
Palomar_2
230
230
0
2
2-900 ACSS/AW
41
Old Town_1
230
230
0
2
2-605 ACSS/AW
42
East County
Eco Gen 1
230
230
0
2
2-1113 ACSS/AW
43
Miguel
Bay Blvd
230
230
10
2
2-900 ACSS/AW
44
Miguel_1
230
230
23
2
2-1033.5 ACSR/AW
45
_4
230
230
1
2
2-605 ACSS/AW
46
Sycamore Canyon
230
230
4
2
2-900 ACSS/AW
47
Miguel
230
230
9
2
2-605 ACSS/AW
48
230
230
15
2
2-636 ACSS/AW
49
230
230
1
2
2-1033.5 ACSR/AW
50
_3
230
230
1
2
2-1109 ACAR
51
Mission
230
230
8
2
1-1109 ACAR
52
Miguel
230
230
9
2
2-605 ACSS/AW
53
230
230
1
2
2-1109 ACAR
54
230
230
9
2
2-1033.5 ACSR/AW
55
Mission
230
230
15
2
2-636 ACSS/AW
56
Bay Boulavard
230
230
2.83
1
2-3500 KCMIL CU
57
230
230
1.00
1
2-4000 KCMIL CU
58
Silvergate
230
230
4.00
1
2-900 ACSS/AW
59
Old Town_1
230
230
0.00
1
2-1109 ACAR
60
Mission_1
230
230
4
2
1-1109 ACAR
61
Old Town_2
230
230
0.09
1
2-1109 ACAR
62
230
230
4
2
1-1109 ACAR
63
Old Town_3
230
230
7
2
1-3500 KCMIL CU
64
Silvergate_1
230
230
1
2
1-2500 KCMIL CU
65
Old Town_4
230
230
7
2
1-3500 KCMIL CU
66
Silvergate
230
230
1
2
1-2500 KCMIL CU
67
Talega
230
230
34.24
1
1-1033.5 ACSR/AW
68
230
230
8
2
1-1033.5 ACSR/AW
69
Escondido
230
230
9
2
1-1033.5 ACSR/AW
70
Otay Mesa
230
230
0.11
1
2-900 ACSS/AW
71
Tijuana
230
230
2.00
1
2-1033.5 ACSR/AW
72
Otay Mesa
Miguel
230
230
9
2
2-900 ACSS/AW
73
Miguel
230
230
24
2
2-1033.5 ACSR/AW
74
_3
230
230
1
2
2-605 ACSS/AW
75
Sycamore
230
230
4
2
2-1109 ACAR
76
Otay Mesa
Miguel
230
230
9
2
2-900ACSS/AW
77
Miguel
230
230
10
2
2-900ACSS/AW
78
Bay Blvd
230
230
0.17
1
2-5000 KCMIL CU
79
Imperial Valley
NOSDGE23043_1
230
230
0.00
1
2-1033.5 ACSS/AW
80
IV Bay 12N
NOSDGE23045-6_1
230
230
0.00
2
2-1113 ACSR
81
IV Bay 13N
NOSDGE23045-6_1
230
230
0.00
2
2-1113 ACSR
82
IV Bay 13S
NOSDGE23047-8_1
230
230
0.00
2
2-954 AL
83
IV Bay 14S
NOSDGE23047-8_1
230
230
0.00
2
2-954 AL
84
Imperial Valley
La Rosita
230
230
6
2
2-900 ACSS/AW
85
Palomar Energy
230
230
1
2
2-900 ACSS/AW
86
230
230
12
2
2-1109 ACAR
87
_1
230
230
6.18
1
2-1109 ACAR
88
_2
230
230
5
2
2-1033.5 ACSR/AW
89
Sycamore
230
230
0.36
1
2-1033.5 ACSR/AW
90
Talega
230
230
0.00
1
2-1033.5 ACSR/AW
91
230
230
6
2
1-1033.5 ACSR/AW
92
San Onofre_1
230
230
1
2
2-1033.5 ACSR/AW
93
Encina_1
230
230
10
2
2-1109 ACAR
94
Penasquitos
230
230
8
2
2-1033.5 ACSR/AW
95
Sycamore Canyon
230
230
22
2
2-900 ACSS/AW
96
Suncrest
230
230
6
2
2-4000 KCMIL CU
97
Sycamore Canyon
230
230
22
2
2-900 ACSS/AW
98
Suncrest_1
230
230
6
2
2-4000 KCMIL CU
99
SCR
SCR SVC SUB
230
230
100
Imperial Valley
NOSDGE23061_1
230
230
0.00
1
2-900 ACSS/AW
101
Imperial Valley
230
230
3
2
2-900 ACSS/AW
102
230
230
0
2
2-900 ACSS/AW
103
230
230
2
2
2-900 ACSS/AW
104
Drew Switchyard
230
230
0
1
2-900 ACSS/AW
105
Drew Switchyard
NOSDGE23067_1
230
230
0.00
1
2-900 ACSS/AW
106
Drew Switchyard
POCO
230
230
0.00
1
1-900 ACSS/AW
107
DREW Switchyard
DW GEN 7
230
230
0.00
1
1-1250 KCMIL AL
108
Pio Pico  Generator
Otay Mesa Sy
230
230
0.04
1
1-1272 ACSS
109
Penasquitos
230
230
3
2
2-900 ACSS/AW
110
_1
230
230
11.00
1
2-4000 KCMIL CU
111
230
230
1.00
1
2-4000 KCMIL CU ENAMEL
112
Sycamore Canyon
230
230
0.00
1
2-5000 KCMIL CU ENAMEL
113
Encina
Encina Gen 1
230
230
0.03
1
1-3500 CU
114
OM
OM GEN 4
230
230
0
1
1-1033.5 ACSR/AW
115
San Luis Rey
230
230
0
2
2-1033.5 ACSR/AW
116
GIS Terminal
230
230
0
2
1-5000 KCMIL CU
117
San Luis Rey_1
230
230
0
2
2-1033.5 ACSR/AW
118
GIS Terminal_2
230
230
0
2
1-5000 KCMIL CU
119
Imperial Valley
Phase Shifting Transformer
230
230
0
2
2-900 ACSS/AW
120
Z172244
Z172242
230
230
0
2
2-1033.5 ACSR/AW
121
Z189533
Z189535
230
230
0.27
1
1-1033.5 ACSR/AW
122
East County
Eco Gen 1
230
230
0
2
2-1113 ACSS/AW
123
Drew Switchyard
230
230
2
2
2-900 ACSS/AW
124
Z46503
230
230
1
2
2-900 ACSS/AW
125
Encina Switchyard
138
230
0
2
2-1033.5 ACSR/AW
126
Cannon
138
230
0
2
2-1109 ACAR
127
Encina Switchyard
138
230
1
2
2-1109 ACAR
128
138
230
17.00
1
2-636 ACSR/AW
129
Z105030
Batiquitos
138
230
1.00
1
1-1750 MCM AL
130
138
230
0.72
1
2-1750 MCM AL
131
Penasquitos
138
230
3
2
2-1033.5 ACSR/AW
132
Palomar
138
138
0.03
1
2-1033.5 ACSR/AW
133
Batiquitos
138
230
3
2
2-1109 ACAR
134
Encina Switchyard_1
138
230
1
2
2-1109 ACAR
135
Palomar
138
230
2
2
2-1033.5 ACSR/AW
136
Telegraph Canyon
Proctor Valley
138
138
3
2
2-636 ACSS/AW
137
Friars
138
138
0.17
1
2-2500 CU
138
_1
138
138
4
2
1-636 ACSR/AW
139
138
138
2
2
1-400 MCM CU
140
_2
138
138
5.43
1
1-636 ACSR/AW
141
Penasquitos
138
138
1
2
1-636 ACSR/AW
142
Doublet Tap
138
138
1
3
1-336 ACSR/AW
143
Doublet
138
138
1
2
1-336 ACSR/AW
144
Shadowridge
Z119772
138
138
4
2
1-1033.5 ACSR/AW
145
Z119772
138
138
0.00
1
1-250 MCM CU
146
NC Metering
138
138
0.39
1
1-336 ACSR/AW
147
Z119772
138
230
1
2
2-1033.5 ACSR/AW
148
Chicarita
138
138
11.00
1
1-636 ACSR/AW
149
Telegraph Canyon
138
138
0.03
1
2-1033.5 ACSR/AW
150
138
138
6
2
2-636 ACSR/AW
151
138
138
4.04
1
1-2500 KCMIL CU
152
Z223732
138
138
1
1-1033.5 ACSR/AW
153
Z189532
138
138
4.00
1
2-400 MCM CU
154
138
138
0.00
1
2-636 ACSS/AW
155
Grant Hill
138
138
1.00
1
2-636 ACSR/AW
156
San Juan Capistrano
138
138
0.10
1
1-1033.5 ACSR/AW
157
138
138
2
2
1-1033.5 ACSR/AW
158
138
138
0.11
1
1-3000 KCMIL CU
159
138
138
5
2
1-636 ACSR/AW
160
Pico
138
138
0
2
1-1750 MCM CU
161
Santee
138
138
2.00
1
1-1033.5 ACSR/AW
162
138
138
5
2
1-605 ACSS/AW
163
138
138
0.00
1
2-336 ACSR/AW
164
Los Coches
138
138
0.00
1
2-636 ACSR/AW
165
Sycamore
138
138
0.20
1
1-3000 KCMIL CU
166
Chicarita
138
138
6.00
1
1-636 ACSR/AW
167
Sycamore
138
138
7
2
1-900 ACSS/AW
168
Santee
138
138
1.55
1
1-900 ACSS/AW
169
Mission
138
138
0.00
1
2-336.4 ACSR
170
138
138
3
2
2-336.4 ACSR
171
Z677977
Z874970
138
138
5.00
2
4-336.4 MCM
172
Z874970
Carlton Hills
138
138
1
2
1-900 ACSS/AW
173
Telegraph Canyon
138
138
0.04
1
2-1033.5 ACSR/AW
174
138
138
3
2
2-636 ACSR/AW
175
Miguel 60 Tap
138
138
1
2
2-636 ACSR/AW
176
Miguel 60 Tap
Miguel
138
138
1
2
2-900 ACSS/AW
177
Miguel 60 Tap
Z119793
138
138
0.02
1
2-636 ACSS/AW
178
Z119793
Z200591
138
138
0.50
1
2-636 ACSR/AW
179
138
138
13
2
1-636 ACSS/AW
180
Los Coches
138
138
1
2
1-636 ACSR/AW
181
Batiquitos
138
138
3
2
2-1033.5 ACSR/AW
182
Shadowridge
138
138
4
2
2-1033.5 ACSR/AW
183
Miguel
138
138
1.00
1
2-636 ACSS/AW
184
Proctor Valley
138
138
1
2
2-636 ACSR/AW
185
Friars
138
138
0.09
1
1-1750 KCMIL AL
186
Mission
138
138
1
2
1-900 ACSS/AW
187
Sycamore_1
138
138
4
2
1-900 ACSS/AW
188
138
138
2
2
1-900 ACSS/AW
189
Carlton Hills
138
138
1
2
1-900 ACSS/AW
190
Trabuco
138
138
1.00
1
1-1033.5 ACSR/AW
191
138
138
0.00
1
2-1033.5 ACSR/AW
192
138
138
3.00
1
1-1750 KCMIL AL
193
Margarita
138
138
0.00
1
1-1750 KCMIL CU
194
Talega
Rancho Mission Viejo
138
138
6.42
1
1-1033.5 ACSR/AW
195
Trabuco
138
138
3.66
1
1-1033.5 ACSR/AW
196
138
138
0
2
1-1033.5 ACSR/AW
197
_1
138
138
6
2
1-1033.5 ACSR/AW
198
Pico_1
138
138
0
2
1-1750 MCM CU
199
Capistrano
138
138
4.00
1
1-1033.5 ACSR/AW
200
Trabuco
138
138
0
2
1-1033.5 ACSR/AW
201
San Mateo_1
Talega
138
138
1.00
1
1-1033.5 ACSR/AW
202
Talega Tap_1
138
138
3
2
1-336.4 ACSR/AW
203
_2
138
138
8.00
1
1-336.4 ACSR/AW
204
_1
138
138
2
2
1-1750 KCMIL AL
205
Laguna Niguel_1
138
138
0.00
1
1-1750 KCMIL AL
206
Pico
138
138
1
2
1-900 ACSS/AW
207
Talega
138
138
0.41
1
1-1033.5 ACSR/AW
208
Capistrano
138
138
0.00
1
1-636 ACSR/AW
209
138
138
0
2
1-336.4 ACSR/AW
210
138
138
1.00
1
1-336.4 ACSR/AW
211
Laguna Niguel
138
138
2
2
1-1750 KCMIL AL
212
Rancho Mission Viejo
Margarita
138
138
3.00
1
1-1033.5 ACSR/AW
213
Mission
138
138
2.56
1
2-636 ACSR/AW
214
Grant Hill
138
138
3.00
1
1-2500 MCM CU
215
Cannon
Encina Hub
138
138
1
2
2-1109 ACAR
216
Encina Hub
Shadowridge
138
138
7.00
1
1-900 ACSS/AW
217
East County
138
138
7.00
1
2-900 ACSS/AW
218
138
138
6.00
1
2-2500 KCMIL CU
219
138
138
1.12
1
2-3000 KCMIL CU
220
Boulevard East
138
138
0.00
1
2-5000 KCMIL CU
221
Pico
138
138
1
2
1-1033.5 ACSR/AW
222
Talega
138
138
0.47
1
1-1033.5 ACSR/AW
223
Talega
138
138
3
2
1-336.4 ACSR/AW
224
San Mateo
138
138
1
2
1-1033.5 ACSR/AW
225
Encina
Z124528
138
230
0
2
2-1033.5 ACSR
226
Z124528
Cannon
138
230
0
2
2-1109 ACAR
227
Boulavard
Boulevard East
238
138
1
1
2-2500 KCMIL CU
228
East County
Eco Gen 2
138
138
0.00
1
1-636 ACSR/AW
229
Encina
Encina Gen 1
138
138
0.00
1
1-636 KCMIL ACSR
230
13822
De-Energized
138
138
0.00
1
1-1109 ACAR
231
13832
De-Energized
138
138
3.00
1
1-336.4 ACSR
232
13832
De-Energized
138
138
3.00
1
1-250 MCM CU
233
13811
De-Energized
138
138
1.07
1
1-900 ACSS/AW
234
13811
De-Energized
138
138
6.00
1
1-250 MCM CU
235
Cannon_1
Encina Hub
138
138
1
2
2-1109 ACAR
236
Encina Hub
Calavera Tap
138
138
0.00
1
1-1033.5 ACSR/AW
237
Encina Hub
Calavera Tap
138
138
2.94
1
1-636 ACSS/AW
238
Calavera Tap
San Luis Rey
138
138
3.89
1
1-1033.5 ACSR/AW
239
Bay Blvd
138
138
3
2
2-636 ACSR/AW
240
Telegraph Canyon
138
138
3
2
2-400 MCM CU
241
69 kV CIRCUITS
707.00
25
125
242
69 kV CIRCUITS
7.00
1
243
69 kV CIRCUITS
43.00
2
244
69 kV CIRCUITS
20.00
51
245
69 kV CIRCUITS
62.00
1
246
Cost of Line
(d)
205,126,609
(e)
3,680,008,465
(f)
3,885,135,074
247
Expenses, Except ISO Charge
(g)
17,861,047
(i)
26,129,028
(j)
3,946,818
(k)
47,936,893
248
ISO Charges
(h)
3,708,419
(l)
3,708,419
36 TOTAL
1,445
680
514
205,126,609
3,680,008,465
3,885,135,074
21,569,466
26,129,028
3,946,818
51,645,312


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: LengthForStandAloneTransmissionLines
San Diego Gas & Electric owns 85.64% and Imperial Irrigation District owns 14.36%.
(b) Concept: LengthForStandAloneTransmissionLines
San Diego Gas & Electric owns 85.64% and Imperial Irrigation District owns 14.36%.
(c) Concept: LengthForStandAloneTransmissionLines
Line has two sections: Palo Verde to North Gila, and North Gila to Colorado River. SDG&E owns 76.22% and 85.64%, respectively, while Arizona Public Service owns 23.78% and 14.36%, respectively.
(d) Concept: CostOfLandAndLandRightsTransmissionLines
Costs available in total only.
(e) Concept: ConstructionAndOtherCostsTransmissionLines
Costs available in total only.
(f) Concept: OverallCostOfTransmissionLine
Costs available in total only.
(g) Concept: OperatingExpensesOfTransmissionLine
Costs available in total only.
(h) Concept: OperatingExpensesOfTransmissionLine
Costs available in total only.
(i) Concept: MaintenanceExpensesOfTransmissionLine
Costs available in total only.
(j) Concept: RentExpensesOfTransmissionLine
Costs available in total only.
(k) Concept: OverallExpensesOfTransmissionLine
Costs available in total only.
(l) Concept: OverallExpensesOfTransmissionLine
Costs available in total only.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
TRANSMISSION LINES ADDED DURING YEAR
  1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines.
  2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
  3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
LINE DESIGNATION SUPPORTING STRUCTURE CIRCUITS PER STRUCTURE CONDUCTORS LINE COST
Line No.
TransmissionLineStartPoint
From
TransmissionLineEndPoint
To
LengthOfTransmissionLineAdded
Line Length in Miles
SupportingStructureOfTransmissionLineType
Type
AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles
Average Number per Miles
NumberOfTransmissionCircuitsPerStructurePresent
Present
NumberOfTransmissionCircuitsPerStructureUltimate
Ultimate
ConductorSize
Size
ConductorSpecification
Specification
ConductorConfigurationAndSpacing
Configuration and Spacing
OperatingVoltageOfTransmissionLine
Voltage KV (Operating)
CostOfLandAndLandRightsTransmissionLinesAdded
Land and Land Rights
CostOfPolesTowersAndFixturesTransmissionLinesAdded
Poles, Towers and Fixtures
CostOfConductorsAndDevicesTransmissionLinesAdded
Conductors and Devices
Asset Retire. Costs
CostOfTransmissionLinesAdded
Total
SupportingStructureConstructionType
Construction
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
(q)
1
OVERHEAD
2
Z125642
Z31482
(a)
0.14
6
2
2
9'
138
761,929
507,913
1,269,842
3
SAN JUAN CAPISTRANO
Z125642
(b)
0.12
6
2
2
9'
138
575,708
575,708
4
LOVELAND_1
Z293866
0.34
9
2
2
9'
69
5
LOVELAND_2
Z293866
(c)
0.34
9
2
2
9'
69
541,083
96,102
637,185
6
LAS PULGAS_1
JAPANESE MESA
(d)
6.65
9
1
1
9'
69
1,732,888
10,423,043
3,938,625
16,094,556
7
LAS PULGAS_2
JAPANESE MESA
(e)
6.66
9
1
1
6'
69
1,982,819
1,982,819
8
UNDERGROUND
9
SAN JUAN CAPISTRANO
Z125642
(f)
0.11
1
1
9"
138
913,080
913,080
10
Z293865_1
Z293866
0.08
2
2
9"
69
11
Z293865_2
Z293866
(g)
0.08
2
2
9"
69
2,250,327
2,250,327
44
TOTAL
1.20
48
15
15
1,732,888
11,726,055
7,706,047
2,558,527
23,723,517


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: LengthOfTransmissionLineAdded
To report addition of 0.14 miles for TL13816 from Structure Z125642 to Structure Z31482 for 2021.
(b) Concept: LengthOfTransmissionLineAdded
To report removal of 0.12 miles for TL13816 from San Juan Capistrano Substation to Structure Z125642 for 2021.
(c) Concept: LengthOfTransmissionLineAdded
To report addition of 0.34 miles for TL6914 and TL6957 from Loveland Substation to Structure Z293866 for 2021.
(d) Concept: LengthOfTransmissionLineAdded
To report re-build of 6.65 miles for TL692 from Las Pulgas Substation to Japanese Mesa Substation for 2021.
(e) Concept: LengthOfTransmissionLineAdded
To report removal of 6.66 miles for TL692 from Las Pulgas Substation to Japanese Mesa Substation for 2021.
(f) Concept: LengthOfTransmissionLineAdded
To report addition of 0.11 miles for TL13816 from San Juan Capistrano Substation to Structure Z125642 for 2021.
(g) Concept: LengthOfTransmissionLineAdded
To report addition of 0.08 miles for TL6914 and TL6957 from Structure Z293865 to Structure Z293866 for 2021.

Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
SUBSTATIONS
  1. Report below the information called for concerning substations of the respondent as of the end of the year.
  2. Substations which serve only one industrial or street railway customer should not be listed below.
  3. Substations with capacities of Less than 10 MVA except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown.
  4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).
  5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity.
  6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Character of Substation VOLTAGE (In MVa) Conversion Apparatus and Special Equipment
Line No.
SubstationNameAndLocation
Name and Location of Substation
(a)
SubstationCharacterDescription
Transmission or Distribution
(b)
SubstationCharacterAttendedOrUnattended
Attended or Unattended
(b-1)
PrimaryVoltageLevel
Primary Voltage (In MVa)
(c)
SecondaryVoltageLevel
Secondary Voltage (In MVa)
(d)
TertiaryVoltageLevel
Tertiary Voltage (In MVa)
(e)
SubstationInServiceCapacity
Capacity of Substation (In Service) (In MVa)
(f)
NumberOfTransformersInService
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
ConversionApparatusAndSpecialEquipmentType
Type of Equipment
(i)
NumberOfConversionApparatusAndSpecialEquipmentUnits
Number of Units
(j)
CapacityOfConversionApparatusAndSpecialEquipment
Total Capacity (In MVa)
(k)
1
ALPINE, Alpine
Distribution
Unattended
69
12
0
56
2
2
AMHERST, San Diego
Distribution
Unattended
12
4
0
6
1
3
ARTESIAN, San Diego
Distribution
Unattended
69
12
0
56
2
4
ASH, Escondido
Distribution
Unattended
69
12
0
84
3
1
5
AVOCADO, Fallbrook
Distribution
Unattended
69
12
0
41
2
6
B , San Diego
Distribution
Unattended
69
12
0
112
4
7
BARRETT, Barrett
Distribution
Unattended
69
12
0
13
1
8
BASILONE, San Clemente
Distribution
Unattended
69
12
0
28
1
9
BATIQUITOS, Encinitas
Distribution
Unattended
138
12
0
56
2
1
10
BERNARDO, Rancho Bernardo
Distribution
Unattended
69
12
0
140
5
11
BORDER-, San Diego
Distribution
Unattended
69
12
0
56
2
12
BORREGO-, Borrego Springs
Distribution
Unattended
69
12
0
26
2
13
BOSTONIA, El Cajon
Distribution
Unattended
12
4
0
10
1
14
BOULEVARD EAST, Boulevard
Distribution
Unattended
138
12
0
28
1
15
CABRILLO, San Diego
Distribution
Unattended
69
12
0
56
2
16
CALAVO GARDENS, El Cajon
Distribution
Unattended
12
4
0
7
2
17
CAMERON,  Campo
Distribution
Unattended
69
12
0
6
1
18
CANNON, Carlsbad
Distribution
Unattended
138
12
0
112
4
19
CAPISTRANO, San Juan Capistrano
Distribution
Unattended
138
12
0
56
2
20
CARLTON HILLS, Santee
Distribution
Unattended
138
12
0
56
2
21
CENTRAL, San Diego
Distribution
Unattended
12
4
0
6
1
22
CHICARITA, San Diego
Distribution
Unattended
138
12
0
84
3
23
CHOLLAS , Lemon Grove
Distribution
Unattended
69
12
0
56
2
1
24
CLAIREMONT, San Diego
Distribution
Unattended
69
12
0
56
2
25
CORONADO, Coronado
Distribution
Unattended
69
12
0
56
2
26
CREELMAN, Ramona
Distribution
Unattended
69
12
0
84
3
27
CRESTWOODCampo
Distribution
Unattended
69
12
0
13
1
28
CRISTIANITOS Mission Viejo
Distribution
Unattended
69
12
0
8
1
29
DEL MAR, Del Mar
Distribution
Unattended
69
12
0
84
3
30
DESCANSO, Descanso
Distribution
Unattended
69
12
0
7
1
31
DIVISION, San Diego
Distribution
Unattended
69
12
0
53
2
32
DUNHILL-San Diego
Distribution
Unattended
69
4
0
8
1
33
EAST OCEANSIDE, Oceanside
Distribution
Unattended
12
4
0
6
1
34
EASTGATE, San Diego
Distribution
Unattended
69
12
0
56
2
35
EL CAJON, El Cajon
Distribution
Unattended
69
12
0
112
4
36
ELLIOTT, San Diego
Distribution
Unattended
69
12
0
84
3
37
ENCINITAS_1, Encinitas
Distribution
Unattended
69
12
0
56
2
38
ENCINITAS_2, Encinitas
Distribution
Unattended
12
4
0
6
1
39
ESCO_1, Escondido
Distribution
Unattended
69
12
0
56
2
40
ESCO_2, Escondido
Distribution
Unattended
12
4
0
4
1
41
ESCONDIDO, Escondido
Distribution
Unattended
69
12
0
112
4
42
F  , San Diego
Distribution
Unattended
69
12
0
84
3
43
FELICITA,Escondido
Distribution
Unattended
69
12
0
84
3
44
FRIARS, San Diego
Distribution
Unattended
138
12
0
56
2
45
GARFIELD, El Cajon
Distribution
Unattended
69
12
0
28
1
46
GENESEE,San diego
Distribution
Unattended
69
12
0
112
4
47
GLENCLIFF-GC
Distribution
Unattended
69
12
0
7
1
48
GRANITE, El Cajon
Distribution
Unattended
69
12
0
112
4
49
GRANT HILLSan Diego
Distribution
Unattended
138
12
0
56
2
50
HILLTOP, San Diego
Distribution
Unattended
12
4
0
3
1
51
IMPERIAL BEACH_1, Imperial Beach
Distribution
Unattended
69
12
0
56
2
52
IMPERIAL BEACH_2, Imperial Beach
Distribution
Unattended
12
4
0
6
1
53
JAMACHA, Jamacha
Distribution
Unattended
69
12
0
84
3
54
JAPANESE MESA, San Clemente
Distribution
Unattended
69
12
0
14
2
55
KEARNY WEST, San Diego
Distribution
Unattended
69
12
0
112
4
1
56
KETTNER,San Diego
Distribution
Unattended
69
12
0
56
2
57
KYOCERA, San Diego
Distribution
Unattended
69
12
0
9
1
58
LA JOLLA, La Jolla
Distribution
Unattended
69
12
0
56
2
59
LAGUNA NIGUEL, Laguna Niguel
Distribution
Unattended
138
12
0
112
4
60
LAS PULGAS-Oceanside
Distribution
Unattended
69
12
0
28
1
61
LILAC, Valley Center
Distribution
Unattended
69
12
0
56
2
62
LINCOLN ACRES, National City
Distribution
Unattended
12
4
0
6
1
63
LOS COCHES, Lakeside
Distribution
Unattended
69
12
0
84
3
64
LOVELAND, Alpine
Distribution
Unattended
69
12
0
28
1
65
MARGARITA, Mission Viejo
Distribution
Unattended
138
12
0
112
4
66
MELROSE, Vista
Distribution
Unattended
69
12
0
112
4
67
MESA HEIGHTS,SanDiego
Distribution
Unattended
69
12
0
84
3
68
MESA RIM, San Diego
Distribution
Unattended
69
12
0
112
4
69
MIRAMAR, San Diego
Distribution
Unattended
69
12
0
84
3
70
MIRA SORRENTO,San Diego
Distribution
Unattended
69
12
0
56
2
71
MISSION, San Diego
Distribution
Unattended
69
12
0
112
4
72
MONSERATE, Fallbrook
Distribution
Unattended
69
12
0
56
2
73
MONTGOMERY, Chula Vista
Distribution
Unattended
69
12
0
56
2
74
MORRO HILL, Oceanside
Distribution
Unattended
69
12
0
13
1
75
MURRAY, La Mesa
Distribution
Unattended
69
12
0
112
4
1
76
NATIONAL CITY, National City
Distribution
Unattended
69
4
12
14
2
77
NAVAL STATION Switchyard, San Diego-NSM
Distribution
Unattended
69
0
0
0
78
NORTH CITY WEST, San Diego
Distribution
Unattended
69
12
0
56
2
79
NORTH VISTA-,Vista
Distribution
Unattended
12
4
0
3
1
80
OCEAN RANCH, Oceanside
Distribution
Unattended
69
12
0
56
2
81
OCEANSIDE, Oceanside
Distribution
Unattended
69
12
0
56
2
82
OLD TOWN, San Diego
Distribution
Unattended
69
12
0
84
3
2
83
OLIVENHAIN-, Escondido
Distribution
Unattended
69
12
0
28
1
84
OTAY LAKES, Chula Vista
Distribution
Unattended
69
12
0
5
1
85
OTAY. Chula Vista
Distribution
Unattended
69
12
0
56
2
1
86
PACIFIC BEACH, San Diego
Distribution
Unattended
69
12
0
56
2
87
PALA, San Diego County
Distribution
Unattended
69
12
0
28
1
88
PALOMAR AIRPORT, Carlsbad
Distribution
Unattended
138
12
0
84
3
89
PARADISE, San Diego
Distribution
Unattended
69
12
0
56
2
90
PENDLETON, Oceanside
Distribution
Unattended
69
12
0
56
2
91
PICO, San Clemente
Distribution
Unattended
138
12
0
56
2
92
POINT LOMA SEWAGE, San Diego
Distribution
Unattended
12
4
0
13
1
93
POINT LOMA, San Diego
Distribution
Unattended
69
12
0
84
3
94
POMERADO, San Diego
Distribution
Unattended
69
12
0
84
3
95
POWAY, Poway
Distribution
Unattended
69
12
0
56
2
96
PROCTOR VALLEY, Bonita
Distribution
Unattended
138
12
0
56
2
1
97
RAMONA, Ramona
Distribution
Unattended
12
4
0
6
1
98
RANCHO CARMEL, San Diego
Distribution
Unattended
69
12
0
84
3
99
RANCHO MISSION VIEJO, Rancho Mission Viejo
Distribution
Unattended
138
12
0
56
2
100
RANCHO SANTA FE_1, RanchoSantaFe
Distribution
Unattended
69
12
0
41
2
101
RANCHO SANTA FE_2, RanchoSantaFe
Distribution
Unattended
69
4
0
6
1
102
RINCON, Rincon
Distribution
Unattended
69
12
0
25
2
103
ROLANDO, San Diego
Distribution
Unattended
12
4
0
13
2
104
ROSE CANYON, San Diego
Distribution
Unattended
69
12
0
56
2
105
SALT CREEK, Chula Vista
Distribution
Unattended
69
12
0
56
2
106
SAMPSON, San Diego
Distribution
Unattended
69
12
0
112
4
107
SAN CLEMENTE, San clemente
Distribution
Unattended
12
4
0
3
1
108
SAN LUIS REY-Oceanside
Distribution
Unattended
69
12
0
112
4
109
SAN MARCOS, San Marcos
Distribution
Unattended
69
12
0
112
4
110
SAN MATEO, San Clemente
Distribution
Unattended
138
12
0
45
2
111
SAN YSIDRO, San Ysidro
Distribution
Unattended
69
12
0
56
2
112
SANTA YSABEL, Santa Ysabel
Distribution
Unattended
69
12
0
12
1
113
SANTEE, Santee
Distribution
Unattended
138
12
0
56
2
114
SCRIPPS, San Diego
Distribution
Unattended
69
12
0
84
3
115
SEWAGE PUMP STA (3)., San Diego
Distribution
Unattended
12
4
0
46
6
116
SHADOWRIDGE, Vista
Distribution
Unattended
138
12
0
84
3
117
SHORECLIFFS-San Clemente
Distribution
Unattended
12
4
0
3
1
118
SOUTH SAN CLEMENTE, San clemente
Distribution
Unattended
12
4
0
3
1
119
SPRING VALLEY, Spring Valley
Distribution
Unattended
69
12
0
56
2
120
STREAMVIEW, San Diego
Distribution
Unattended
69
12
0
56
2
121
STUART, Oceanside
Distribution
Unattended
69
12
0
8
1
122
SUNNYSIDE, San Diego
Distribution
Unattended
69
12
0
28
1
123
SWEETWATER, National City
Distribution
Unattended
69
12
0
56
2
1
124
TELEGRAPH CANYON, Chula Vista
Distribution
Unattended
138
12
0
112
4
125
TORREY PINES, San Diego
Distribution
Unattended
69
12
0
112
4
126
TRABUCO, San Juan Capistrano
Distribution
Unattended
138
12
0
112
4
127
UCM switchyard, San Diego
Distribution
Unattended
69
128
URBAN-, San Diego
Distribution
Unattended
69
12
0
84
3
129
VALLEY CENTER, Valley Center
Distribution
Unattended
69
12
0
28
1
130
VINE
Distribution
Unattended
69
12
0
56
3
131
VISTA, Vista
Distribution
Unattended
12
4
0
10
2
132
WARNERS. Warner Springs
Distribution
Unattended
69
12
0
28
1
133
WARREN CANYON_1, Poway
Distribution
Unattended
69
12
0
8
1
134
WARREN CANYON_2, Poway
Distribution
Unattended
69
4
0
7
1
135
WITHERBY-San Diego
Distribution
Unattended
12
4
0
6
1
136
BAY BOULEVARD
Transmission
Unattended
230
69
0
448
2
137
DOUBLETT switchyard, San Diego
Transmission
Unattended
138
69
138
EAST COUNTY_1, Boulevard
Transmission
Unattended
500
230
12
1120
1
139
EAST COUNTY_2, Boulevard
Transmission
Unattended
230
138
0
392
1
140
ENCINA switchyard, Carlsbad
Transmission
Unattended
138
141
ENCINA, Carlsbad
Transmission
Unattended
230
138
0
784
2
142
ESCONDIDO, Escondido
Transmission
Unattended
230
69
0
672
3
143
GOAL LINE, Escondido
Transmission
Unattended
69
144
IMPERIAL VALLEY, El Centro
Transmission
Unattended
500
230
12
2840
9
2
145
LOS COCHES, Lakeside
Transmission
Unattended
138
69
0
448
2
146
MIGUEL_1, Bonita
Transmission
Unattended
230
69
0
448
2
147
MIGUEL_2, Bonita
Transmission
Unattended
230
138
0
784
2
148
MIGUEL_3, Bonita
Transmission
Unattended
500
230
12
2240
6
1
500/17
2
500
149
MIRAMAR GT, San Diego
Transmission
Unattended
12
69
0
50
1
150
MISSION_1, San Diego
Transmission
Unattended
138
69
0
200
1
151
MISSION_2, San Diego
Transmission
Unattended
230
69
0
224
1
152
MISSION_3, San Diego
Transmission
Unattended
230
138
0
784
2
153
NARROWS, borrego Springs
Transmission
Unattended
88
69
12
10
3
154
OCOTILLO switchyard, Ocotillo
Transmission
Unattended
500
155
OLD TOWN, San Diego
Transmission
Unattended
230
69
0
448
2
156
OTAY MESA switchyard, Chula Vista
Transmission
Unattended
230
157
PENASQUITOS_1, San Diego
Transmission
Unattended
138
69
0
520
3
158
PENASQUITOS_2, San Diego
Transmission
Unattended
230
138
0
392
1
1
159
PENASQUITOS_3, San Diego
Transmission
Unattended
230
69
0
448
2
160
SAN LUIS REY, Oceanside,
Transmission
Unattended
230
69
0
672
3
230/17
2
500
161
SILVERGATE, San Diego
Transmission
Unattended
230
69
0
448
2
1
162
SONGS
Transmission
Unattended
230
230
0
250
230/17
1
250
163
SUNCREST, Japatul
Transmission
Unattended
500
230
12
2240
6
1
164
SYCAMORE CANYON_1, San Diego
Transmission
Unattended
230
69
0
672
3
1
165
SYCAMORE CANYON_2, San Diego
Transmission
Unattended
230
138
0
392
1
1
166
TALEGA_1, San Clemente
Transmission
Unattended
138
69
0
140
1
1
167
TALEGA_2, San Clemente
Transmission
Unattended
230
138
0
1102
4
230/17
2
500
168
WABASH switchyard, San Diego
Transmission
Unattended
69
0
169
Total
1,750


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
  1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
  2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general".
  3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.
Description of the Good or Service
(a)
Name of Associated/Affiliated Company
(b)
Account(s) Charged or Credited
(c)
Amount Charged or Credited
(d)
1
Non-power Goods or Services Provided by Affiliated
2
Construction Work in Progress
Sempra Energy
(a)
5,962,280
3
Underground line expenses
Sempra Energy
71
4
Meter Expenses
Sempra Energy
8,712
5
Miscellaneous Distribution Expenses
Sempra Energy
260,633
6
Maintenance supervision and engineering
Sempra Energy
785
7
Maintenance of station equipment
Sempra Energy
612
8
Maintenance of Overhead Lines
Sempra Energy
5,201
9
Maintenance of Lines
Sempra Energy
495
10
Maintenance of meters
Sempra Energy
516
11
Operation supervision and engineering
Sempra Energy
6,003
12
Compressor station labor and expenses
Sempra Energy
238
13
Measuring and regulating station expenses.
Sempra Energy
261
14
Maintenance of mains
Sempra Energy
26,131
15
Maintenance of measuring and regulating station equipment
Sempra Energy
87
16
Operation Supervision and Engineering
Sempra Energy
54,443
17
Mains and services expenses
Sempra Energy
14,873
18
Meter and House Regulator Expenses
Sempra Energy
394
19
Customer installations expenses
Sempra Energy
25,369
20
Distribution Other Expenses
Sempra Energy
35,320
21
Other Utility Plant
Sempra Energy
227,935
22
Maintenance of mains_2
Sempra Energy
4,035
23
Maintenance of Services
Sempra Energy
45
24
Maintenance of Meters and House Regulators
Sempra Energy
497
25
Maintenance of other equipment.
Sempra Energy
58
26
Meter Reading Expenses
Sempra Energy
8,142
27
Customer Records and Collection Expenses
Sempra Energy
20,770
28
Customer Assistance Expenses
Sempra Energy
11,304
29
Miscellaneous Customer Service and Informational Expenses
Sempra Energy
478,436
30
Office Supplies and Expenses
Sempra Energy
793,511
31
Outside Services Employed
Sempra Energy
60,940,954
32
Property Insurance
Sempra Energy
422,094
33
Injuries and Damages
Sempra Energy
128,572
34
Employee Pension and Benefits
Sempra Energy
51,228,787
35
Regulatory Commission Expenses
Sempra Energy
128,835
36
Miscellaneous General Expense
Sempra Energy
1,613,323
37
Maintenance of General Plant
Sempra Energy
9,667
38
Purchased Power
Energia Sierra Juarez
17,576,300
39
Construction Work in Progress
Southern California Gas Company
11,761,732
40
Accounts Receivable from Associated Companies
Sempra Energy
888
41
Accum Prov for Deprec
Southern California Gas Company
9,880
42
Other Utility Plant
Southern California Gas Company
3,145,178
43
3rd Party Bill A/R-Clearing
Southern California Gas Company
218,163
44
Stores Expense Undistributed
Southern California Gas Company
673,394
45
Clearing Accounts
Southern California Gas Company
1,034,254
46
Miscellaneous Deferred Debits
Southern California Gas Company
54,461
47
RD&D EXPENDITURES
Southern California Gas Company
418,804
48
Accounts Payable
Southern California Gas Company
49,193
49
Expense of NonUtility Operations
Southern California Gas Company
32,342
50
Expenditures for Certain Civic, Political and Related Activities
Southern California Gas Company
81,639
51
Other Gas Revenues
Southern California Gas Company
409,050
52
Miscellaneous Transmission Expenses
Southern California Gas Company
3,153
53
Miscellaneous Distribution Expenses
Southern California Gas Company
804
54
Natural Gas TR Line Prch
Southern California Gas Company
6,592
55
Cpmpressor Stn Exp
Southern California Gas Company
64,211
56
GTO Operations Supervision & Engineering
Southern California Gas Company
4,797,241
57
System Control & Load Dispatch
Southern California Gas Company
918,759
58
Communication System Expenses
Southern California Gas Company
1,641,177
59
Stores Expense Undistributed
Sempra Energy
5,558
60
Other Expenses
Southern California Gas Company
518,486
61
TIMP-Main Supv & Eng
Southern California Gas Company
75,182
62
GTM Maintenance Mains
Southern California Gas Company
882,746
63
Operation Supervision and Engineering
Southern California Gas Company
4,194,249
64
Routine Leak Survey
Southern California Gas Company
70,908
65
TIMP-MEAS&REG STA-CG
Southern California Gas Company
6,074
66
Distribution Other Expenses
Southern California Gas Company
90,260
67
GDM Maintenance Mains
Southern California Gas Company
48,413
68
Maintenance / Meters & Hse Reg
Southern California Gas Company
409,931
69
Meter Reading Expenses
Southern California Gas Company
180,816
70
Customer Records and Collection Expenses
Southern California Gas Company
1,742,989
71
Customer Assistance Expenses
Southern California Gas Company
644,838
72
Informational and Instructional Advertising Expenses
Southern California Gas Company
28,609
73
Outside Services Employed
Southern California Gas Company
62,860,321
74
Injuries and Damages
Southern California Gas Company
721,806
75
Employee Pension and Benefits
Southern California Gas Company
136,178
76
Regulatory Commission Expenses
Southern California Gas Company
2,335,783
77
Miscellaneous General Expense
Southern California Gas Company
174,618
78
Prepayments
Sempra Energy
258,293,644
79
Rents
Southern California Gas Company
1,427,376
80
Maintenance of General Plant
Southern California Gas Company
620,281
81
Unamortized Debt Expense
Sempra Energy
1,200,083
82
Operation supervision and engineering_1
Sempra Energy
748
83
Miscellaneous Steam Power Expenses_2
Sempra Energy
636
84
Maintenance of miscellaneous steam plant_3
Sempra Energy
87
85
Operation Supervision and Engineering_4
Sempra Energy
312
86
Miscellaneous other power generation expenses_5
Sempra Energy
236
87
Maintenance of miscellaneous other power generation plant_6
Sempra Energy
7,525
88
System control and load dispatching_7
Sempra Energy
36
89
Other expenses_8
Sempra Energy
637
90
Transmission Operation Supv & Engineering_9
Sempra Energy
185,450
91
Load Dispatch_10
Sempra Energy
1,872
92
Station expenses_11
Sempra Energy
1,955
93
Miscellaneous Transmission Expenses_12
Sempra Energy
169,165
94
Operation supplies and expenses._13
Sempra Energy
301
95
Maintenance of Structures_14
Sempra Energy
5,256
96
Maintenance of station equipment_15
Sempra Energy
4,087
97
Maintenance of overhead lines_16
Sempra Energy
1,685
98
Distribution Operation Supv & Engineering_17
Sempra Energy
41,621
99
Load dispatching_18
Sempra Energy
1,680
100
Other regulatory assets
Sempra Energy
624,985
101
Clearing Accounts
Sempra Energy
2,183,385
102
Deferred Debits
Sempra Energy
624,950
103
Accumulated provision for property insurance.
Sempra Energy
11
104
Accumulated miscellaneous operating provisions
Sempra Energy
112,630
105
Accounts Payable
Sempra Energy
247,743
106
Other Deferred Credits
Sempra Energy
3,677,982
107
Other regulatory liabilities
Sempra Energy
624,985
108
Expenses of Nonutility Operations
Sempra Energy
2,164,775
109
Expenditures for Certain Civic, Political and Related Activities
Sempra Energy
1,619
110
Other Deductions
Sempra Energy
35,011
111
Other Electric Revenues
Sempra Energy
1,224
19
20
Non-power Goods or Services Provided for Affiliated
21
Accounting & Finance
Sempra Energy
1,354,048
22
External Affairs
Southern California Gas Company
2,554,875
23
Human Resources
Southern California Gas Company
234,583
24
Information Technology
Southern California Gas Company
80,203,088
25
Real Estate & Facilities
Southern California Gas Company
1,651,963
26
Supply Management
Southern California Gas Company
897
27
Depreciation Expense
Sempra Energy
1,191,286
28
Environmental Services
Sempra Energy
37,948
29
External Affairs
Sempra Energy
268,836
30
Human Resources
Sempra Energy
8,952,092
31
Information Technology
Sempra Energy
3,307,058
32
Real Estate & Facilities
Sempra Energy
4,599,090
33
Supply Management
Sempra Energy
1,592,981
34
Depreciation Expense
Sempra International Mexico
4
35
Engineering / Const. Services
Sempra International Mexico
70,032
36
Human Resources
Sempra International Mexico
160,470
37
Information Technology
Sempra International Mexico
888,301
38
Depreciation Expense
Sempra LNG
15,895
39
Human Resources
Sempra LNG
235,019
40
Information Technology
Sempra LNG
632,934
41
Real Estate & Facilities
Sempra LNG
626
42
Supply Management
Sempra LNG
8,175
43
Accounting & Finance
Southern California Gas Company
31,012,571
44
Customer Services
Southern California Gas Company
172,826
45
DepreciationExpense
Southern California Gas Company
8,485,018
46
Engineering and Construction Services
Southern California Gas Company
207,075
47
Environmental Services
Southern California Gas Company
38,346
42


Name of Respondent:

San Diego Gas & Electric Company
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/15/2022
Year/Period of Report

End of:
2021
/
Q4
FOOTNOTE DATA

(a) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies
All non-power goods and services provided by affiliated companies are billed to San Diego Gas and Electric at fully loaded cost.

(Rows 2-19, 43-60, 83-100, 123-138)
Fully loaded costs include all direct expenses, indirect overheads and shared service billing. Shared service non‑power goods and service support cost are based on allocation process methodologies for Sempra Energy Corporate Center cost centers. The following information regarding multi‑factor and causal‑beneficial relationship information was provided by the Sempra Energy Corporate Center Budget and Reporting Manager and is a summary of the varying methodologies used:

Multi‑factor basic, also known as "Four‑Factor", this method is used by a department for which there is no causal relationship. The Multi‑factor basic weights four factors equally for each business unit: Revenues, Operating Expenses, Gross Plant and Investment, and Employees
Multi‑factor basic without ONCOR, also known as "Four‑Factor", this method is used by a department for which there is no causal relationship. The Multi‑factor basic weights four factors equally for each business unit: Revenues, Operating Expenses, Gross Plant and Investment, and Employees (EXCLUDES ONCOR)
Multi‑factor Utility, this method uses the same four factors that appear in Multi‑factor (basic), but calculates ratios for California utility business units only
Multi‑factor split, this method divides costs 50% to Utilities, 50% to Global. The Multi‑factor (basic) percentages are the basis for the allocation between Southern California Gas Company and San Diego Gas and Electric, and between Global Business Units
Multi‑factor split without ONCOR, this method divides costs 50% to Utilities, 50% to Global. The Multi‑factor (basic) percentages are the basis for the allocation between Southern California Gas Company and San Diego Gas and Electric, and between Global Business Units (EXCLUDES ONCOR)
5 executive cost centers allocated using the weighted average of the annual labor budget for departments that report to the respective executive
Causal - Executive Security, this method accounts for the transportation services available to Corporate officers and considers their allocation methods in general. The CEO (retained) has one dedicated driver, while the other 3 drivers are available to other executives and assumes an even allocation of Utility, Global and additional retained. The result is 25% Utility, 25% Global and 50% Retained for 4 drivers
Causal – Fire Insurance, this method allocates all costs for Fire Insurance based on miles of electrical lines per business unit
Causal – Full Time Employee Equivalents, total Full Time Employee equivalents (FTE’s) are used as the basis for allocation of most Human Resource departmental services provided on behalf of all the business units. The Sempra Energy Corporate Center FTE’s are re‑allocated by Multi‑factor (basic) to result in a blended rate
Causal – Executive Full Time Employee Equivalents, this method allocated the support and administration cost for executive related services using a weighted average of participating officers. Executives are heavily weighted (75%) compared to Directors and Vice Presidents (25%). The Sempra Energy Corporate Center shared service Executives are then Multi‑factored (basic) resulting in a blended percentage
Causal – My Info Services Contract, My Info services cost is allocated by the number of people in the My Info system. The portion of services attributable to Sempra Energy Corporate Center amount is then re‑allocated by Multi‑factor (basic) to result in a blended percentage
Causal – Headquarter Security, this method allocates the costs of Sempra Energy Corporate Center security, excluding the Headquarter guard service contract, by the Causal - Full Time Employee Equivalent method, and allocates the Headquarter guard service contract by the ratio of employees occupying the Sempra Energy Corporate Center Headquarter building
Causal – Tax Services, this allocation is a weighted average of the workload of each employee within the Tax department based on an annual time study. The Sempra Energy Corporate Center workload hours are re‑allocated using Multi‑factor (basic) resulting in a blended percentage
Causal – Hyperion Financial Management and Consolidation System, this allocation is a weighted average of the headcount of Hyperion Financial Management and Consolidation System users. The Sempra Energy Corporate Center amount is then re‑allocated by Multi‑factor (basic) to result in a blended percentage for each business unit
Causal – FLP (Financial Leadership Program), this allocation is a weighted average of the employees in the Financial Leadership Program based on the business units they support. The Sempra Energy Corporate Center workload is then re‑allocated by Multi‑factor (basic) to result in a blended percentage
Causal - Citizenship Engagement, this method uses the Multi-Factor Basic allocation as a starting point, then reduces the percentages to exclude a portion attributed to managing costs which are retained
Causal – Global Risk, Energy Risk Management estimates the percentage of hours worked on both market risk (energy risk and Dodd Frank) and the credit risk by business unit
Causal – Group Executive Insurance, this method allocates the group executive insurance policy using a weighted average of covered officers, per their assigned business unit. The Sempra Energy Corporate Center FTE’s are reallocated by multi-factors
Causal – Pension, this method allocates based on the summary value of Sempra Energy’s major pension savings funds and San Diego Gas & Electric’s Nuclear Decommissioning Trust (NDT). The Sempra Energy Corporate Center and Sempra Global value is then re-allocated by the US-based FTE’s, with Sempra Energy Corporate Center FTE’s further re-allocated based on Multi‑factor (basic)
Causal – Treasury, for the Finance department, the Assistant Treasurer estimates percentages of effort for the business units based on significant projects requiring financing or advisory work
Causal – Law Department, this allocation method is based on direct time charged by attorneys, paralegal and law clerks in the Archer timekeeping system during the previous Jan-Sep period. Hours for Sempra Energy Corporate Center are re-allocated by Multi-Factor Basic, resulting in a blended percentage
Causal – Audit Plan, this method is based on the Audit hours planned for each business unit in the coming year. The portion of services attributable to Sempra Energy Corporate Center is re-allocated using Multi-Factor basic method to result in a blended percentage for each business unit
Causal – SOX, this allocation is a weighted average of the workload of each employee within SOX Compliance based on an annual time study. Sempra Energy Corporate Center workload hours are reallocated using Multi-Factor Basic, resulting in a blended percentage
Causal – Bank Reconciliations and Escheatment, for the Bank Reconciliation and Escheatment department, the estimated percentages of effort for the business units based on the bank reconciliation and escheatment activity for the upcoming period
Causal – Security Services, this method accounts for the call-in transportation services available to Corporate Officers and Executives. These call-in services are primarily provided to Corporate Officers and Executives at the California Utilities and for Mexico and South America. Occasionally, these services may be provided to Officers and Executives in other business units or at Sempra Energy Corporate Center. In this instance, these costs will be directly charged to the respective business unit or retained at Sempra Energy Corporate Center
Causal – Sempra HQ CSOC Depreciation, needs to be allocated by this method, San Diego Gas & Electric 72.7% other affiliates 25.9%
Causal – Sacramento Office Depreciation, needs to be allocated by this method, San Diego Gas & Electric 50%, other affiliates 50%
Causal - VP Tax, this allocation is a weighted average of the workload of each employee within the Tax department based on an annual time study. Parent workload hours are reallocated using Multi-Factor Basic, resulting in a blended percentage
Causal – Cash Management, for the Cash Management department, the Director estimates percentages based on volumes and time involved in the business units funding activities
Causal – Executive Benefits (Southern California Gas Company), direct restricted stock and stock options expense for Southern California Gas Company executives is allocated because some executives are shared by more than one business unit. The percentages reflect a weighted average of each executive's work distribution among business units
Causal – Executive Benefits (San Diego Gas and Electric), direct restricted stock and stock options expense for San Diego Gas and Electric executives is allocated because some executives are shared by more than one business unit. The percentages reflect a weighted average of each executive's work distribution among business units
Shared asset allocation of depreciation expense associated with capitalized assets at each shared service entity are allocated uniquely depending on its allocation of benefit or supporting purpose, and follow as such:

Causal – HQ Depreciation – depreciation expense & ROR related to "HQ leasehold improvements" is allocated based on the square footage directly occupied by the business units. Corporate Center's direct occupation except for the portion which is retained, is re-allocated based on the Multi-Factor base allocation
Causal - CCURE System, this allocation is a weighted average of the number of card readers used per business unit for depreciation of the CCURE 9000 Security System. Sempra Energy Corporate Center units are reallocated using Multi-factor Basic, resulting in a blended percentage
Causal – Headquarters Occupancy, Rent, depreciation & ROR related to new headquarters that is allocated based on the square footage directly occupied by the business units. Sempra Energy Corporate Center’s direct occupation, except for an executive portion which is retained, is reallocated based on the Multi-Factor Basic. Amenity floors in the HQ are excluded, as they benefit all occupants ratably


(Rows 163-180, 203-220, 243-244)
Fully loaded costs include all direct expenses, indirect overheads and shared service billing. Shared service non-power goods and service support cost are based on allocation process methodologies for 133 Southern California Gas Company cost centers. The following causal beneficial relationship information is a summary of the 22 varying methodologies used:
29 cost centers used a form of LAN ID counts to determine the shared allocation
28 cost centers used a ratio of miles to pipe
12 cost centers used a form of weighted average allocation of time by inherent knowledge of the manager/planner assessment within the cost center department
9 cost centers used a form of allocation of computer and/or server system and resource usage statistics
8 cost centers used a form of prior year project assignments as a base for the current year distribution, which is adjusted as necessary when current year projects begin or change and impact the current allocation
7 cost centers used a form of departmental studies based on current year budgeted activities and/or dollars
7 cost centers used a form of the existing current year Sempra Energy Corporate Center four factor multi factor allocation which includes weighted averages of operating revenue, operating expenses, gross plant and investment and Full Time Employee equivalent numbers
6 cost centers used a form of gas meter counts and service territory allocations
5 cost centers used a form of a ratio of horsepower in compressor engines in the service territory
5 cost centers used a form of Full Time Employee equivalent statistics for support
3 cost centers used a study based on cases worked by both regulated and non-regulated companies
2 cost centers used a form of an allocation of space study identifying building square footage assigned
2 cost centers used a study based on volumes of items mailed and payments processed and the allocation of employee time
2 cost centers used a form of allocation based on gas flow throughput

There was one use by a cost center of each of the remaining allocation methodologies: Communication by stakeholders
An employee matrix
Call volume
Claims processed over a five-year period
A meter ratio applied to specific budgeted activity
A mileage ratio applied to specific budgeted activity
The number of network sites
The number of SAP ID’s
A workload distribution study


(Row 21-42, 61-65)
All non‑power goods and services provided by San Diego Gas and Electric are billed at fully loaded cost.
(Row 21)
Affiliate companies charged by San Diego Gas and Electric for less than $250,000 include: Sempra International South America, Sempra International Mexico.

(Rows 21-42, 61-65)
Fully loaded costs include all direct expenses, indirect overheads and, where applicable, a labor premium required by the Enova/Pacific Enterprises Merger Decision (D.98‑03‑073) for shared service billing. The Merger Decision also requires San Diego Gas and Electric to charge employee transfer fees to an affiliated company. Shared service non‑power goods and service support cost are based on allocation process methodologies for 112 San Diego Gas and Electric cost centers. The following causal‑beneficial relationship information is a summary of the 19 varying methodologies used:
37 cost centers used a form of LAN ID counts to determine the shared allocation
19 cost centers used a form of weighted average allocation of time by inherent knowledge of the manager/planner assessment within the cost center department
17 cost centers used a form of an allocation of space study identifying building square footage assigned
9 cost centers used a form of prior year project assignments as a base for the current year distribution, which is adjusted as necessary when current year projects begin or change and impact the current allocation
8 cost centers use a form of workload distribution study
4 cost centers used the existing current year Sempra Energy Corporate Center four factor multi‑factor allocation which includes weighted averages of operating revenue, operating expenses, gross plant and investment and Full Time Employee equivalent numbers
3 cost centers used a form of budgeted current year project assignments
2 cost centers were charged 100% to Sempra Energy Corporate Center
2 cost centers used a form of a count of network sites
2 cost centers used a form of the number of contracts supported

There was one use by a cost center of each of the remaining allocation methodologies:
An allocation of time by Vice President or Director’s assessment of planned current year project assignments within the cost center, which is adjusted as necessary when current year projects begin or change and impact the current allocation and current years budgeted activities by Affiliate
Archibus transactional data for Facilities work requests and projects
A unit of measure based on San Diego Gas & Electric and Southern California Gas call volume
Based on the number of MYINFO user accounts
A form of Full Time Employee equivalent statistics for support
The number of full-time equivalent employees benefited by the activity
The number of SAP ID’s
A form of allocation of computer and/or server system and resource usage statistics
An allocation based on the number of applications used for DevSecOps
XBRL Instance File
Visit Submission Details Screen